ML15219A599

IR 05000275/2015002, 05000323/2015002; 04/01/2015 - 06/30/2015; Diablo Canyon Power Plant; Fire Protection, Licensed Operator Requalification, Problem Identification and Resolution, Follow-up of Events and Notices of Enforcement Discretion

ML15219A599
Person / Time
Site:	Diablo Canyon
Issue date:	08/07/2015
From:	Thomas Hipschman NRC/RGN-IV/DRP/RPB-A
To:	Halpin E Pacific Gas & Electric Co
RYAN ALEXANDER
References
EA-15-040 IR 2015002
Download: ML15219A599 (52)

See also: IR 05000275/2015002

Text

UNITED STATES

NUCLEAR REGULATORY COMMISSION

REGION IV

1600 E. LAMAR BLVD.

ARLINGTON, TX 76011-4511

August 7, 2015

EA-15-040

Mr. Edward D. Halpin

Senior Vice President

And Chief Nuclear Officer

Pacific Gas and Electric Company

Diablo Canyon Power Plant

P.O. Box 56, Mail Code 104/6

Avila Beach, CA 93424

SUBJECT: DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION

REPORT 05000275/2015002 and 05000323/2015002

Dear Mr. Halpin:

On June 30, 2015, the U.S. Nuclear Regulatory Commission (NRC) completed an inspection at

your Diablo Canyon Power Plant Units 1 and 2. On July 7 and 28, 2015, the NRC inspectors

discussed the results of this inspection with Mr. James Welsh and other members of your staff.

Inspectors documented the results of this inspection in the enclosed inspection report.

NRC inspectors documented six findings of very low safety significance (Green) in this report.

Five of these findings involved a violation of NRC requirements, and one was determined to be

Severity Level IV under the traditional enforcement process.

Further, inspectors documented two licensee-identified violations which were determined to be

Severity Level IV in this report. The NRC is treating these violations as non-cited violations

(NCVs) consistent with Section 2.3.2.a of the NRC Enforcement Policy.

One of the licensee identified violations referenced above resulted in an NRC investigation. The

enclosed report documents the investigation completed on March 10, 2015, by the Nuclear

Regulatory Commission's Office of Investigations. The purpose of this investigation was to

determine whether on three separate occasions in 2014, a former licensee employee willfully

failed to perform transient combustible permit inspections and falsified inspections documents

regarding the completion of those inspections. Based on the evidence gathered during the

investigation, the NRC concluded that on three separate occasions in 2014, a former licensee

employee deliberately failed to perform the subject transient combustible permit inspections and

falsified inspection documents regarding the completion of those inspections at the Diablo

Canyon Power Plant. This was contrary to the fire protection plan as required by License

Conditions 2.C.(5) and 2.C.(4) of licenses DPR-80 and DPR-82, respectively, and resulted in a

violation. The NRC concluded that information regarding: (1) the reason for the violation, (2) the

corrective actions that have been taken and results achieved, and (3) the date when full

compliance was achieved is adequately addressed on the docket in the enclosed inspection

E. Halpin -2-

report. Therefore, you are not required to respond to this letter unless the description herein

does not accurately reflect your corrective actions or your position.

If you contest the violations or significance of these NCVs, you should provide a response within

30 days of the date of this inspection report, with the basis for your denial, to the U.S. Nuclear

Regulatory Commission, ATTN: Document Control Desk, Washington, DC 20555-0001; with

copies to the Regional Administrator, Region IV; the Director, Office of Enforcement,

U.S. Nuclear Regulatory Commission, Washington, DC 20555-0001; and the NRC resident

inspector at the Diablo Canyon Power Plant.

If you disagree with a cross-cutting aspect assignment in this report, you should provide a

response within 30 days of the date of this inspection report, with the basis for your

disagreement, to the Regional Administrator, Region IV; and the NRC resident inspector at the

Diablo Canyon Power Plant.

In accordance with Title 10 of the Code of Federal Regulations (10 CFR) 2.390, Public

Inspections, Exemptions, Requests for Withholding, a copy of this letter, its enclosure, and your

response (if any) will be available electronically for public inspection in the NRCs Public

Document Room or from the Publicly Available Records (PARS) component of the NRC's

Agencywide Documents Access and Management System (ADAMS). ADAMS is accessible

from the NRC Web site at http://www.nrc.gov/reading-rm/adams.html (the Public Electronic

Reading Room).

Sincerely,

/RA R. Alexander for/

Thomas Hipschman, Acting Branch Chief

Projects Branch A

Division of Reactor Projects

Docket Nos. 05000275, 05000323

License Nos. DPR-80, DPR-82

Enclosure:

Inspection Report 05000275/2015002 and

05000323/2015002

w/ Attachment: Supplemental Information

cc w/ enclosure: Electronic Distribution

SUNSI Review ADAMS Non-Sensitive Publicly Available

By: RDA Yes No Sensitive Non-Publicly Available

OFFICE SRI:DRP/A RI:DRP/A C:DRS/EB1 C:DRS/EB2 C:DRS/OB C:DRS/PSB1 C:DRS/PSB2

NAME THipschman JReynoso TFarnholtz GPick VGaddy MHaire HGepford

SIGNATURE /RA/ via E /RA/ via T /RA/ /RA/ /RA/ /RA/ /RA/

DATE 08/06/15 08/07/15 07/30/15 08/03/15 08/03/15 07/31/15 08/03/15

OFFICE TL:DRS/TSS SPE:DRP/A ORA/ACES SRA:TSB AC:DRP/A

NAME ERuesch RAlexander MHay DLoveless THipschman

SIGNATURE /RA/ /RA/ /RA/ /RA/ /RA/

HFreeman for JKramer for RAlexander

for

DATE 08/03/15 08/05/15 08/06/15 08/03/15 08/07/15

Letter to Edward D. Halpin from Thomas Hipschman dated August 7, 2015

SUBJECT: DIABLO CANYON POWER PLANT - NRC INTEGRATED INSPECTION

REPORT 05000275/2015002 and 05000323/2015002

DISTRIBUTION:

Regional Administrator (Marc.Dapas@nrc.gov)

Deputy Regional Administrator (Kriss.Kennedy@nrc.gov)

DRP Director (Troy.Pruett@nrc.gov)

DRP Deputy Director (Ryan.Lantz@nrc.gov)

DRS Director (Anton.Vegel@nrc.gov)

DRS Deputy Director (Jeff.Clark@nrc.gov)

Senior Resident Inspector (Thomas.Hipschman@nrc.gov)

Resident Inspector (John.Reynoso@nrc.gov)

Administrative Assistant (Madeleine.Arel-Davis@nrc.gov)

Acting Branch Chief, DRP/A (Thomas.Hipschman@nrc.gov)

Senior Project Engineer, DRP/A (Ryan.Alexander@nrc.gov)

Project Engineer, DRP/A (Thomas.Sullivan@nrc.gov)

Public Affairs Officer (Victor.Dricks@nrc.gov)

Public Affairs Officer (Lara.Uselding@nrc.gov)

Project Manager (Siva.Lingam@nrc.gov)

Acting Team Leader, DRS/TSS (Eric.Ruesch@nrc.gov)

RITS Coordinator (Marisa.Herrera@nrc.gov)

ACES (R4Enforcement.Resource@nrc.gov)

Regional Counsel (Karla.Fuller@nrc.gov)

Technical Support Assistant (Loretta.Williams@nrc.gov)

RIV Congressional Affairs Officer (Angel.Moreno@nrc.gov)

RIV/ETA: OEDO (Cindy.Rosales-Cooper@nrc.gov)

ROPreports

U.S. NUCLEAR REGULATORY COMMISSION

REGION IV

Docket: 05000275; 05000323

License: DPR-80; DPR-82

Report: 05000275/2015002; 05000323/2015002

Licensee: Pacific Gas and Electric Company

Facility: Diablo Canyon Power Plant, Units 1 and 2

Location: 7 1/2 miles NW of Avila Beach

Avila Beach, CA

Dates: April 1 through June 30, 2015

Inspectors: T. Hipschman, Senior Resident Inspector

J. Reynoso, Resident Inspector

R. Alexander, Senior Project Engineer

T. Buchanan, Operations Engineer

M. Hayes, Operations Engineer

M. Kennard, Operations Engineer

Approved Thomas Hipschman, Acting Chief

By: Projects Branch A

Division of Reactor Projects

-1- Enclosure

SUMMARY

IR 05000275/2015002, 05000323/2015002; 04/01/2015 - 06/30/2015; Diablo Canyon Power

Plant; Fire Protection, Licensed Operator Requalification, Problem Identification and Resolution,

Follow-up of Events and Notices of Enforcement Discretion

The inspection activities described in this report were performed between April 1 and

June 30, 2015, by the resident inspectors at Diablo Canyon Power Plant and inspectors from

the NRCs Region IV office. Six findings of very low safety significance (Green) are documented

in this report. Five of these findings involved violations of NRC requirements, and one was

determined to be Severity Level IV under the traditional enforcement process. The significance

of inspection findings is indicated by their color (Green, White, Yellow, or Red), which is

determined using Inspection Manual Chapter 0609, Significance Determination Process. Their

cross-cutting aspects are determined using Inspection Manual Chapter 0310, Aspects within

the Cross-Cutting Areas. Violations of NRC requirements are dispositioned in accordance with

the NRC Enforcement Policy. The NRCs program for overseeing the safe operation of

commercial nuclear power reactors is described in NUREG-1649, Reactor Oversight Process.

Cornerstone: Initiating Events

• Green. The inspectors identified a Green, non-cited violation of 10 CFR 50.65(b)(2) for the

licensees failure to appropriately scope the 230 kV switchyard in the Maintenance Rule

monitoring program. Specifically, from the inception of the facilities monitoring program

through May 18, 2015, the licensee failed to properly scope or evaluate the 230 kV

switchyard to include the entire switchyard up through the first inter-tie circuit breakers

CB262 and CB282 into the Maintenance Rule program. Electrical faults within the 230 kV

switchyard can cause loss of offsite power which is relied upon to mitigate accidents and

cause an actuation of a safety-related systems, such as, emergency diesel generators, and

should have been included into its Maintenance Rule program. This issue was entered into

the licensees corrective action program as Notifications 50702970 and 50703118.

The inspectors determined that the licensees failure to scope the 230 kV offsite power

source including the switchyard up through the first breakers from the transmission system

into the Maintenance Rule program was contrary to the requirements of 10 CFR 50.65 and

therefore a performance deficiency. The performance deficiency was determined to be

more than minor because it is associated with the initiating events attribute of protections

against external factors and adversely affected the cornerstone objective, in that, a 230 kV

switchyard failure can upset plant stability and challenge critical safety functions during

shutdown as well as power operations. Failure to monitor the performance or condition of

230 kV offsite power source (including the switchyard up through the first breakers from the

transmission system) in a manner sufficient to provide reasonable assurance the offsite

power was capable of fulfilling the intended functions affected the reliability of the plant

equipment to perform their safety function. The inspectors determined if the 230 kV

switchyard was properly scoped into the Maintenance Rule program the loss of offsite power

due to the flash over event may have been prevented. However the direct cause of the

event has been identified as untimely corrective actions associated with an ineffective

corrective action program. As such, improper Maintenance Rule scoping was not the direct

cause. Therefore, the inspectors determined the finding could be evaluated using the

significant determination process in accordance using IMC 0609, Appendix A, Significance

Determination Process (SDP) for Findings At-Power, Exhibit 1, Initiating Events Screening

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Questions. The inspectors determined that the finding was of very low safety significance

(Green) because the finding was determined not to be the cause of the actual 230 kV failure

such that all of the screening questions in Exhibit 1 could be answered no. The inspectors

determined that since the scoping of the switchyard systems had occurred more than 3

years ago, and the opportunity to reevaluate system scoping had not recently occurred, the

finding did not represent current licensee performance and therefore a cross-cutting aspect

was not assigned. (Section 4OA3.4.b.(1))

• Green. The inspectors reviewed a self-revealing, Green finding for the licensees failure to

adequately implement procedure OM7.ID1, Problem Identification and Resolution, to

prevent a high voltage insulator flashover event in the 230 kV switchyard that occurred on

October 31, 2014. Specifically, corrective actions from three previous root cause

evaluations were not effective to prevent a loss of the 230 kV start-up power and

subsequent auto start of all of the safety standby emergency diesel generators (EDGs). This

issue was entered into the licensees corrective action program as Notification 50699230.

The licensees failure to adequately implement procedure OM7.ID1, Problem Identification

and Resolution was a performance deficiency. The performance deficiency was more than

minor because it was associated with the human performance attribute of the Initiating

Events cornerstone and affected the cornerstone objective to limit the likelihood of those

events that upset plant stability and challenge critical safety functions. Specifically, this

failure resulted in another high-voltage insulator flashover, which resulted in loss of 230 kV

offsite startup power and activation of all safety-related EDGs, on October 31, 2014. In

accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors

determined that the impact of the finding on Unit 1 should be evaluated using Exhibit 1 of

IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at

Power, and further determined that this finding required a detailed risk evaluation by the

regional senior risk analyst because the finding involved a partial loss of offsite power, a

support system that contributes to the likelihood of an initiating event and affected mitigation

equipment.

The risk analyst determined that, with the 230 kV system de-energized, any plant transient

would result in a plant-centered loss of offsite power. Therefore, the risk analyst calculated

the incremental conditional core damage probability for an exposure period of 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> to be

2.09 x 10-7, which is lower than the 1 x 10-6 threshold in the significance determination

process; this finding is of very low safety significance (Green) for Unit 1. In accordance with

IMC 0609.04, Initial Characterization of Findings, the inspectors determined that the

impact of the finding on Unit 2 should be evaluated using IMC 0609, Appendix G, Shutdown

Operations Significance Determination Process, because the finding pertained to

operations, an event, or a degraded condition while the plant was shut down. Unit 2 was

shutdown in a refueling outage when the event occurred on October 31, 2014. Because of

the shutdown configuration of Unit 2, the loss of 230 kV support system did not impact the

ability to continue to provide decay heat removal for the unit. Therefore, the analyst

determined qualitatively that this finding is also of very low safety significance (Green) for

Unit 2. This finding has a cross-cutting aspect of work management, in the area of human

performance, for failing to implement a process of planning, controlling, and executing work

activities such that nuclear safety is an overriding priority. Specifically the licensee failed to

effectively plan and coordinate preventative maintenance strategies associated with root

causes from previous high-voltage insulators flashover or failures since 2008 to prevent the

loss of offsite 230 kV and the transient on October 31, 2014 [H.5]. (Section 4OA3.4.b.(2))

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Cornerstone: Mitigating Systems

• Green. The inspectors identified a Green, non-cited violation of Technical Specification 5.4.1

involving the failure to appropriately pre-plan and implement written procedures associated

with configuration control of the hazard barrier hydrogen guard piping in the proximity and

impacting safety-related equipment. This issue was entered into the licensee corrective

action program as Notification 50778755.

The inspectors determined that the failure to consider the impact to the fire hazard analysis

and the seismic configuration of the hydrogen guard pipe was a performance deficiency.

The performance deficiency was more than minor because it was associated with the

protection against external events attribute of the Mitigating Systems cornerstone and

adversely affected the cornerstone objective to ensure the availability, reliability, and

capability of systems (i.e. hazard barriers) that respond to initiating events, such as fires, to

prevent undesirable consequence. Though there were no actual consequences, the

breaching of the seismically qualified hydrogen guard piping removed a designed hazard

barrier and has the potential to vent hydrogen into rooms containing safety related

equipment. Using IMC 0609, Appendix F, Fire Protection Significance Determination

Process, Phase 1 Worksheet, the finding was determined to be of very low safety

significance (Green) because it represented a low degradation of fire prevention and

administrative controls element of the plant combustible material controls program, and the

breaching of the hydrogen guard piping would not have prevented the safe shutdown of the

plant. This finding has a cross-cutting aspect of design margins associated with the human

performance area. Specifically, the most significant contributor for the performance

deficiency was the licensee did not have an adequate work process that focused on

maintaining defense in depth related to a fire hazard barrier, such as a hydrogen guard

piping, during maintenance activities. Breaching hydrogen guard piping impacts defense in

depth and design margins used to protect safety-related equipment, and special attention is

required to carefully guard and change the configuration with great thought and care [H.6].

(Section 1R05)

• Green - Severity Level IV. The inspectors reviewed a self-revealing, Severity Level IV

non-cited violation of 10 CFR 55.49, Integrity of Examinations and Tests, and an

associated Green finding for the licensees failure to provide adequate examination security

measures during administration of the 2015 biennial requalification examination. On

May 26, 2015, a licensed operator was able to obtain plant computer information that led to

the discovery of specific plant events contained on the NRC-required annual operating test.

The licensee entered this issue into the corrective action program as Notification 50704195

and retested the crew with a new scenario.

The failure of the licensee to provide adequate measures for examination security for the

biennial requalification examinations was a performance deficiency. The performance

deficiency was more than minor, and therefore a finding, because it adversely affected the

human performance attribute of the Mitigating Systems cornerstone objective of ensuring

the availability, reliability, and capability of systems that respond to initiating events to

prevent undesirable consequences. Using NRC Inspection Manual Chapter 0609,

Significance Determination Process, Attachment 4, Tables 1 and 2 worksheets (issue date

June 19, 2012); and the corresponding Appendix I, Licensed Operator Requalification

Significance Determination Process (SDP), Flowchart Block #10 (issue date

December 6, 2011), the finding was determined to have very low safety significance

(Green). Although the 2015 finding resulted in a compromise of the integrity of biennial

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dynamic simulator examinations had no compensatory actions been taken, the equitable

and consistent administration of the biennial dynamic simulator examination was not actually

affected by this compromise. The traditional enforcement violation was determined to be a

Severity Level IV violation consistent with Section 6.4.d of the Enforcement Policy. This

finding has a cross-cutting aspect in the resources component of the human performance

cross-cutting area because the licensee failed to ensure the procedures are adequate to

ensure nuclear safety [H.1]. (Section 1R11)

• Green. The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, involving the licensees failure to ensure credited

design features, such as flow vent paths, protect safety-related systems, from temperature

and pressure effects of a high-energy line break (HELB) in the auxiliary building.

Specifically, the licensee allowed obstruction of a credited flow path with acrylic glass plates

not qualified in the original design and not verified to function under a HELB scenario. The

licensee entered this issue into the corrective action program as Notifications 50697910

and 50698102, and took immediate actions to remove the acrylic glass plates from the vent

path doors in the auxiliary building.

The performance deficiency was determined to be more than minor because it affected the

Mitigating Systems Cornerstone attribute of Design Control and adversely affected the

cornerstone objective of ensuring the reliability, availability and capability of systems that

respond to initiating events to prevent undesirable consequences. Specifically, the licensee

did not have adequate measures in place to ensure that qualified components were

available to mitigate the consequences of a HELB in the auxiliary building. The finding

screened as of very low safety significance (Green) because the finding did not affect the

design or qualification of mitigating structures, systems, and components; the finding did not

represent a loss of system and/or function; the finding did not represent an actual loss of a

function of a single train for greater than the technical specification (TS) allowed outage

time; the finding did not represent an actual loss of a function of one or more non-TS trains

of equipment; and did not screen as potentially risk significant due to a seismic, flooding, or

severe weather initiating event. The finding was not assigned a cross-cutting aspect since

the performance deficiency is not indicative of current plant performance. (Section 4OA2.4)

• Green. The inspectors reviewed a self-revealing Green, non-cited violation of Technical

Specification 3.3.4 Remote Shutdown System, for the licensees failure to maintain

adequate configuration control of fuses associated with an emergency diesel generator

(EDG). The licensees failure to maintain adequate configuration control by not verifying

that fuses were properly installed, and adequate post maintenance testing was performed,

following maintenance activities was a performance deficiency. Specifically, following

the 1R17 refueling outage, from approximately June 13, 2013 until November 22, 2013,

EDG 1-3 would not have been able to perform its remote shutdown function due to not being

able to be adequately operated at the local EDG control cubicle. The licensee entered this

issue into the corrective action program as Notification 50595473, and took prompt actions

to restore the fuses to the correct position and verify the positions of the fuses in the other

EDG output breaker cubicles.

The failure to properly install fuses in the local manual operation circuitry of EDG 1-3 was a

performance deficiency. The performance deficiency was more than minor because it was

associated with the protection against external events (fire) attribute of the Mitigating

Systems Cornerstone, and it adversely affected the cornerstone objective of ensuring the

availability, reliability, and capability of systems that respond to initiating events to prevent

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undesirable consequences. Specifically, it affected the ability to reach and maintain safe

shutdown conditions in case of a fire causing a control room abandonment. The inspectors

evaluated this finding using Inspection Manual Chapter 0609, Appendix F, Fire Protection

Significance Determination Process," dated September 20, 2013. Because it affected the

ability to reach and maintain safe shutdown conditions in case of a fire that led to control

room evacuation, the Phase 2 methodology of Inspection Manual Chapter 0609,

Appendix F, was not appropriate for this finding. Therefore, the senior reactor analyst

performed a Phase 3 evaluation to determine the risk significance. The analyst determined

that the performance deficiency only increased the risk of the plant as it related to the need

to locally control EDG 1-3 following a postulated control room evacuation. The Senior Risk

Analyst determined that the change in core damage frequency was less than 1 x 10-6, and

the finding was not significant with respect to large, early release frequency. The analyst

determined that this finding was of very low risk significance (Green). This finding had a

cross-cutting aspect in the area of human performance associated with the work practices

component, because the licensee did not ensure supervisory and management oversight of

work activities, such that nuclear safety was supported [H.5]. (Section 4OA3.3)

Licensee-Identified Violations

Violations of Severity Level IV that were identified by the licensee have been reviewed by the

inspectors. Corrective actions taken or planned by the licensee have been entered into the

licensees corrective action program. These violations and associated corrective action tracking

numbers (notifications) are listed in Section 4OA7 of this report.

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PLANT STATUS

Units 1 and 2 operated at or near full power for the duration of this inspection period.

REPORT DETAILS

1. REACTOR SAFETY

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, and

Emergency Preparedness

1R01 Adverse Weather Protection (71111.01)

.1 Readiness for Impending Adverse Weather Conditions

a. Inspection Scope

On April 7, 2015, the inspectors completed an inspection of the stations readiness for

impending adverse weather conditions. The inspectors reviewed plant design features,

the licensees procedures to respond to high winds and heavy rains, and the licensees

implementation of these procedures. The inspectors evaluated operator staffing and

accessibility of controls and indications for those systems required to control the plant.

These activities constituted one sample of readiness for impending adverse weather

conditions, as defined in Inspection Procedure 71111.01.

b. Findings

No findings were identified.

.2 Readiness to Cope with External Flooding

a. Inspection Scope

On May 13, 2015, the inspectors completed an inspection of the stations readiness to

cope with external flooding. After reviewing the licensees flooding analysis, the

inspectors chose two plant areas that were susceptible to flooding:

• 230 kV switchyard

• 500 kV switchyard

The inspectors reviewed plant design features and licensee procedures for coping with

flooding. The inspectors walked down the selected areas to inspect the design features,

including the material condition of seals, drains, and flood barriers. The inspectors

evaluated whether credited operator actions could be successfully accomplished.

These activities constituted one sample of readiness to cope with external flooding, as

defined in Inspection Procedure 71111.01.

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b. Findings

No findings were identified.

1R04 Equipment Alignment (71111.04)

Partial Walkdown

a. Inspection Scope

The inspectors performed partial system walk-downs of the following risk-significant

systems:

• May 12, 2015, Unit 1, component cooling water

• May 14, 2015, Unit 2, auxiliary salt water system

• May 22-23, 2015, Unit 2, emergency diesel generator 2-2, fuel oil system

alignment

The inspectors reviewed the licensees procedures and system design information to

determine the correct lineup for the systems. They visually verified that critical portions

of the systems were correctly aligned for the existing plant configuration.

These activities constituted three partial system walk-down samples as defined in

Inspection Procedure 71111.04.

b. Findings

No findings were identified.

1R05 Fire Protection (71111.05)

Quarterly Inspection

a. Inspection Scope

The inspectors evaluated the licensees fire protection program for operational status

and material condition. The inspectors focused their inspection on five plant areas

important to safety:

• April 16, 2015, Unit 1 and 2, auxiliary building 85 foot elevation radiological

control area

• April 22, 2015, Units 1 and 2, cable spreading rooms

• May 12, 2015, Unit 1, component cooling water heat exchanger room

• May 22-23, 2015, Unit 2, turbine building areas located 104 foot elevation

• June 23, 2015, Unit 2, emergency diesel generator rooms

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For each area, the inspectors evaluated the fire plan against defined hazards and

defense-in-depth features in the licensees fire protection program. The inspectors

evaluated control of transient combustibles and ignition sources, fire detection and

suppression systems, manual firefighting equipment and capability, passive fire

protection features, and compensatory measures for degraded conditions.

These activities constituted five quarterly inspection samples, as defined in Inspection

Procedure 71111.05.

b. Findings

Introduction. The inspectors identified a Green non-cited violation of Technical

Specification 5.4.1 involving the failure to appropriately pre-plan and implement written

procedures associated with configuration control of the hazard barrier hydrogen guard

piping in the proximity and impacting safety-related equipment. This issue was entered

into the licensee corrective action program as Notification 50778755.

Description. On January 29, 2015, inspectors observed planned work activity

associated with replacement of Unit 1, volume control tank hydrogen pressure-regulator

and pressure control valve PCV 955. Work Order WO 60075528, temporary work

procedure TP TO-15001, and clearance 1C19-D-08-025 were procedures for planning

and implementing the maintenance activity. The scope of the work directed the

replacement of the hydrogen regulator and required removal of hydrogen guard piping

cover plates to facilitate isolation of the volume control tank (VCT) hydrogen supply.

The current licensing bases at Diablo Canyon permit hydrogen supply pipes routed in

areas containing safety-related equipment only if the piping remains enclosed with a

seismically qualified guard pipe. The seismic design guard pipe is vented to the outside

and is required to be leak tight. The design allows an adequate vent path for the

hydrogen gas to minimize hazards from a hydrogen explosion.

The inspectors noted the Unit 1 hydrogen guard piping is routed in areas of the

auxiliary-control building which contained safety-related equipment. The work had

breached sealed cover plates used to maintain the venting path of the hydrogen gas to

minimize hazards from a hydrogen explosion. The inspector contacted the operations

shift manager to determine if the fire department was aware of the guard piping breach.

The shift manager was not aware of any notification that had been made to the fire

department and documented the inspector concerns in Notification 50684755.

Work Order 60075528 Replacing Unit 1 volume control tank regulator PCV 955, stated

in the Precautions and Limitations: hydrogen gas is present in system which constitutes

an explosive atmosphere hazard. The risk assessment, in accordance with station

procedure AD7 ID14, was evaluated on the impact to primary coolant chemistry, but not

with hazard barrier impact associated with fire hazard analysis. The work procedures

provided hazard material precautionary steps that included testing for hydrogen and use

of non-spark tooling.

On March 19, 2015, in response to the inspectors follow-up concerns on the fire hazard

and seismic configuration control, the licensee concluded the guard pipe was seismically

qualified to provide an additional level of defense in depth to prevent a potential

hydrogen build up in safety-related rooms or rooms with safe shutdown equipment. The

licensee also concluded the guard pipe is credited as a level hazard mitigation by the

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Final Safety Analysis Report Update (FSARU) and other supporting documentation,

however, it is not considered a fire protection impairment per station procedure O8.ID2

which covers fire protection system barriers, suppression, detection, hose reels,

emergency lightings, etc. The licensee concluded that breaching of the system could

introduce a potential hazard if the hydrogen line itself failed and the excess flow shutoff

valves did not actuate.

On March 26, 2015, following the inspectors questions on the licensing basis of the

hydrogen guard piping, the licensee concluded the guard pipe is a unique plant feature

credited in the fire hazards analysis, but because it is not a fire barrier, it is not classified

as part of the Diablo Canyon fire protection system. This conclusion is documented in

Notification 50694348. In response to the licensee assessment of the function of the

hydrogen guard pipe, the inspectors determined the hydrogen guard piping is a hazard

barrier as described in the DCPP Units 1 and 2, FSARU Chapter 9.5A, Fire Hazard

Analysis. The hydrogen line in safety-related areas is design to be protected with a

guard pipe and is associated with in situ combustible materials as part of a system to

vent highly combustible hydrogen gas away from safety-related equipment.

On April 14, 2015, in response to the inspectors concerns regarding the seismic

configuration and controls related to Work Order WO 60075528, Notifications 50697654

and 50697655 were written to ensure requirements of the licensees seismic induced

system interactions program and seismic configuration control program were

appropriately evaluated.

Procedure AD7.DC8, Work Planning, Revision 45, which provides requirements for the

planning of maintenance, states in part:

• Section 8.45.2, A fire protection engineer shall review orders for work on the fire

protection system or for work requiring planned impairments of the fire protection

system

• Section 8.45.5, A piping engineer shall review orders that require dismantling

piping, piping components

• Section 8.64, Seismic Configuration Control, states, in part, engineering

structural review is required on equipment within the seismic configuration control

program, such as the hydrogen guard piping, to ensure personnel do not

invalidate seismic qualification through engineering, construction, maintenance or

procurement activities

• Section 8.65, Seismic Induced Systems Interaction Program (SISIP), has

requirements for planning work to ensure compliance with the SISIP.

Procedure AD4.ID3, Seismic induced system interaction program (SISIP)

Housekeeping Activities, Revision 14, states, in part:

• Maintenance activities that create potential seismic induced system interactions

such as parts resulting from equipment disassembly (i.e., removing cover plates

from hydrogen guard piping) are required to be identified and evaluated.

Procedure OM8, Fire Protection Program, provides elements to ensure the design of

systems, components and structures shall minimize consequences and provide for safe

- 10 -

shutdown in case of fire. The fire protection program brings together diverse elements in

order to meet the goal of defense in depth fire safety. As stated in Section 4.4, Design

and Modification Control, fire protection program will:

• Preclude modifications to plant design which adversely affect fire

detection/suppression equipment, fire-rated barriers and the fire hazards

analysis.

The inspectors determined that the hydrogen guard piping, because it is documented in

the fire hazard analysis section of Diablo Canyon FSARU section 9.5.1, and fire

protection systems are based on known configurations that include both active and the

passive fire protection element (such as hydrogen guard), is integral to the licensees

defense in depth design to assure safe shutdown following a design basis fire.

The inspectors also determined that hydrogen guard piping represents a component with

a certain design margin as equipment important to both roles as a fire hazard barrier and

its seismic configuration. When maintenance is not properly performed, this design

margin is changed which may impact safety-related equipment.

The licensee documented evaluation of NRC Generic Letter 93-06, Highly Combustible

Gas in Vital Areas, in Action Request A0332316; dated December 13, 1995, which

states, in part:

The Guard Pipe is really a ventilation duct which routes any leak in the guarded

hydrogen pipe to outside the building.

In the same response, the licensee evaluation stated, To further minimize hazards from

a hydrogen explosion, hydrogen lines will be rerouted out of certain areas containing

safety-related equipment and will be enclosed within a guarded pipe where its runs in

any areas containing safety-related equipment. The guard pipe will be vented to the

outdoors and will be pressure tested to verify that it is leak tight. Based on this

assessment, the inspectors concluded the hydrogen guard pipe represents a fire hazard

barrier since safety evaluation (SER #8) approved by the NRC on November 15, 1978,

required fire zones containing hydrogen lines be provided with seismic Category I Guard

Pipes installed around these hydrogen lines prior to plant operations.

Analysis. The inspectors determined that the failure to consider the impact to the fire

hazard analysis and the seismic configuration of the hydrogen guard pipe was a

performance deficiency. The inspectors evaluated the performance deficiency in

accordance with Inspection Manual Chapter 0612, Appendix B, Issue Screening. The

performance deficiency was more than minor because it was associated with the

protection against external events attribute of the Mitigating Systems cornerstone and

adversely affected the cornerstone objective to ensure the availability, reliability, and

capability of systems (i.e., hazard barriers) that respond to initiating events, such as

fires, to prevent undesirable consequence. Though there were no actual consequences,

the breaching of the seismically qualified hydrogen guard piping removed a designed

hazard barrier and has the potential to vent hydrogen into rooms containing

safety-related equipment. Using IMC 0609, Appendix F, Fire Protection Significance

Determination Process, Phase 1 Worksheet, the finding was determined to be of very

low safety significance (Green) because it represented a low degradation of fire

prevention and administrative controls element of the plant combustible material controls

- 11 -

program, and the breaching of the hydrogen guard piping would not have prevented the

safe shutdown of the plant.

This finding has a cross-cutting aspect of design margins associated with the human

performance area. Specifically, the most significant contributor for the performance

deficiency was the licensee did not have an adequate work process that focused on

maintaining defense in depth related to a fire hazard barrier, such as a hydrogen guard

piping, during maintenance activities. Breaching hydrogen guard piping impacts defense

in depth and design margins used to protect safety-related equipment, and special

attention is required to carefully guard and change the configuration with great thought

and care [H.6].

Enforcement. Technical Specification 5.4.1.a, states, in part, that Written procedures

shall be established, implemented, and maintained covering the following activities: the

applicable procedures recommended in Regulatory Guide 1.33, Revision 2, Appendix A,

February 1978. Regulatory Guide 1.33, Appendix A, Section 9, states, in part,

Maintenance that can affect the performance of safety-related equipment should be

properly pre-planned and performed in accordance with written procedures, documented

instructions, or drawings appropriate to the circumstances. Procedure AD7.DC8 Work

Planning, requires planning of maintenance to consider areas such as fire protection

hazards, seismic induced system interactions, and changes to seismic configuration of

plant components. Contrary to the above, on January 29, 2015, the licensee failed to

properly pre-plan and perform appropriate evaluation prior to maintenance on equipment

that can affect the performance of safety-related equipment in accordance with the

requirements of Procedure AD7.DC8 Work Planning. Specifically, the licensee

directed operators to perform work on hydrogen guard piping that did not properly

evaluate the impact of the hydrogen guard piping hazard barrier breach. The violation

did not result in any actual consequences, but breaching of the hydrogen guard piping

can introduce a potential fire hazard if the non-seismic hydrogen line leaks. Corrective

actions included revision to work instructions to include notification of fire department of

the breach of the hydrogen guard piping. In addition, work-planning procedures were

revised to ensure properly preplanning and coordination between fire protection and civil

engineering prior to conducting maintenance activities on hydrogen piping.

Because this violation was of very low safety significance and it was entered into the

licensees corrective action program as Notification 50778755, this violation is being

treated as a non-cited violation, consistent with Section 2.3.2.a of the NRC Enforcement

Policy: NCV 05000275/2015002-01, "Failure to Appropriately Pre-plan and Perform

Maintenance on Hydrogen Guard Piping.

1R06 Flood Protection Measures (71111.06)

a. Inspection Scope

On April 16, 2015, the inspectors completed an inspection of the stations ability to

mitigate flooding due to internal causes. After reviewing the licensees flooding analysis,

the inspectors chose one plant area containing risk-significant structures, systems, and

components that were susceptible to flooding:

• April 14-16, 2015, Unit 1 and 2, auxiliary building 85 foot elevation

- 12 -

The inspectors reviewed plant design features and licensee procedures for coping with

internal flooding. The inspectors walked down the selected areas to inspect the design

features, including the material condition of seals, drains, and flood barriers. The

inspectors evaluated whether operator actions credited for flood mitigation could be

successfully accomplished.

These activities constitute completion of one flood protection measures sample, as

defined in Inspection Procedure 71111.06.

b. Findings

No findings were identified.

1R11 Licensed Operator Requalification Program and Licensed Operator Performance

(71111.11)

.1 Review of Licensed Operator Requalification

a. Inspection Scope

On June 18, 2015, the inspectors observed a portion of an annual requalification exam

for a licensed operating crew. The inspectors assessed the simulator and licensed

operator performance during an exam scenario and the corresponding evaluators

critique following the exam scenario. The inspectors also assessed a portion of an

annual requalification test for licensed operators and evaluated a simulator scenario

performed by an operating crew.

These activities constitute completion of one quarterly licensed operator requalification

program sample, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.2 Review of Licensed Operator Performance

a. Inspection Scope

The inspectors observed the performance of on-shift licensed operators in the plants

main control room. At the time of the observations, the plant was in a period of

heightened activity. The inspectors observed the operators performance of the following

activities:

• May 6, 2015, Unit 2, down power and ascension to full power for turbine valve

testing

• June 29, 2015, Unit 1, alarm response due to failed power supply IY-19

In addition, the inspectors assessed the operators adherence to plant procedures,

including and other operations department policies.

- 13 -

These activities constitute completion of two quarterly licensed operator performance

samples, as defined in Inspection Procedure 71111.11.

b. Findings

No findings were identified.

.3 Biennial Review of Requalification Program

The licensed operator requalification program involves two training cycles that are

conducted over a two-year period. In the first cycle, the annual cycle, the operators are

administered an operating test consisting of job performance measures and simulator

scenarios. In the second part of the training cycle, the biennial cycle, operators are

administered an operating test and a comprehensive written examination.

a. Inspection Scope

To assess the performance effectiveness of the licensed operator requalification

program, the inspectors conducted personnel interviews, reviewed both the operating

tests and written examinations, and observed ongoing operating test activities.

The inspectors reviewed operator performance on the written exams and operating

tests. These reviews included observations of portions of the operating tests by the

inspectors. The operating tests observed included 22 job performance measures

and 3 scenarios that were used in the current biennial requalification cycle. These

observations allowed the inspectors to assess the licensee's effectiveness in conducting

the operating test to ensure operator mastery of the training program content. The

inspectors also reviewed medical records of 11 licensed operators for conformance to

license conditions and the licensees system for tracking qualifications and records of

license reactivation for 8 operators.

The results of these examinations were reviewed to determine the effectiveness of the

licensees appraisal of operator performance and to determine if feedback of

performance analyses into the requalification training program was being accomplished.

The inspectors interviewed members of the training department and reviewed minutes of

training review group meetings to assess the responsiveness of the licensed operator

requalification program to incorporate the lessons learned from both plant and industry

events. Examination results were also assessed to determine if they were consistent

with the guidance contained in NUREG 1021, "Operator Licensing Examination

Standards for Power Reactors," Revision 9, Supplement 1, and NRC Inspection Manual

Chapter 0609, Appendix I, "Operator Requalification Human Performance Significance

Determination Process."

In addition to the above, the inspectors reviewed examination security measures,

simulator fidelity, and existing logs of simulator deficiencies.

On June 10, 2015, the licensee informed the inspectors of the completed cycle results

for Unit 1 and 2 for both the written examinations and the operating tests:

• 14 of 16 crews passed the simulator portion of the operating test

- 14 -

• 81 of 87 licensed operators passed the simulator portion of the operating test

• 84 of 85 licensed operators passed the job performance measure portion of the

operating test

• 85 of 85 licensed operators passed the written examination

The individuals that failed the simulator scenario and/or job performance measure

portions of the operating test were remediated, retested, and passed their retake

examinations prior to returning to licensed duties. Individuals who did not complete the

requalification examination during the requalification cycle were administratively

restricted from performing licensed duties until they had successfully completed a

requalification examination.

The inspectors completed one inspection sample of the biennial licensed operator

requalification program.

b. Findings

Introduction. The inspectors reviewed a self-revealing Severity Level IV, non-cited

violation of 10 CFR 55.49, Integrity of Examinations and Tests, and an associated

Green finding for the licensees failure to provide adequate examination security

measures during administration of the 2015 biennial requalification examination. On

May 26, 2015, a licensed operator was able to obtain plant computer information that led

to the discovery of specific plant events contained on the NRC-required annual operating

test. The licensee entered this into their corrective action program as

Notification 50704195 and retested the crew with a new scenario.

Description. The licensee was in the process of administering the dynamic simulator

portion of the 2015 biennial requalification examination. The scenario was to be

administered to three separate crews during the day. The first crew performed the

scenario and during the course of the evaluation created plant trends for plant

parameters that were needed to monitor the plant for specific events using the plant

computer. The first run of the scenario was completed and the simulator was reset

using the guidance in Procedure TQ2.ID4, Training Program Implementation.

The second crew entered the simulator and commenced their board walkdowns.

During the board walkdowns, a licensed operator was setting plant computer screens to

monitor desired parameters during the upcoming session. The operator discovered that

the plant parameters and range values that the previous crew had established during the

first run of the simulator scenario were visible and was able to determine the likely plant

events that were going to be on his examination. Upon being notified of the possible

examination security compromise, the licensee took immediate corrective action,

invalidated the scenario for the affected crew, and administered an alternate scenario.

The licensee also provided interim guidance to modify the exam security for the

simulator plant computer to ensure that type of information is not available in the future.

The examination security compromise was entered into the licensees corrective action

program as Notification 50704195.

The licensee evaluated the examination security for the entire biennial examination

cycle to determine the effect on the equitable and consistent administration of the

examination and previous examinations. This evaluation was submitted to the NRC

- 15 -

on June 10, 2015. The evaluation consisted of interviews that randomly selected two

members of every R147 Biennial NRC examination simulator group, with one member

from the management team and one member from the bargaining unit population of

licensed operators. The interviews were used to determine if, during board walkdowns,

they had encountered any indications such as plant computer screens, inappropriately

filed procedures, or various forms of control board flagging that allowed them to

determine any events in the scenarios given. The result was that no licensed operator

had encountered any such information. The plant computer vulnerability was

determined to have exist since 2008 when the plant computer was upgraded. An

independent review of the past 10 years of annual and biennial inspections was

conducted by NRC staff and there was no indication of changes in examination

performance since the specific vulnerability was introduced in 2008. Based on this

review and the interview results provided by the facility, the inspectors determined there

is no indication that the exam security vulnerability introduced in 2008 had an actual

effect on the results of the current or previous NRC-required examinations.

Analysis. The failure of the licensee to provide adequate measures for examination

security for the biennial requalification examinations was a performance deficiency. The

failure also constitutes a violation of 10 CFR 55.49, which was evaluated through the

traditional enforcement process. The significance determination process, which was

used to evaluate this performance deficiency, does not specifically consider a

performance deficiencys impact on the regulatory process. Thus, although related to a

common regulatory concern, it is necessary to address both the violation and finding

using different processes to correctly reflect both the regulatory importance of the

violation and the safety significance of the associated performance deficiency.

The performance deficiency was more than minor, and therefore a finding, because

it adversely affected the human performance attribute of the Mitigating Systems

cornerstone objective of ensuring the availability, reliability, and capability of

systems that respond to initiating events to prevent undesirable consequences.

Additionally, if left uncorrected, the performance deficiency could have become more

significant in that allowing licensed operators to return to the control room without valid

demonstration of appropriate knowledge on the biennial written examinations could be

a precursor to a more significant event. Using NRC Inspection Manual Chapter 0609,

Significance Determination Process, Attachment 4, Tables 1 and 2 worksheets (dated

June 19, 2012); and the corresponding Appendix I, Licensed Operator Requalification

Significance Determination Process (SDP), Flowchart Block #10 (dated

December 6, 2011), the finding was determined to have very low safety significance

(Green). Although the 2015 finding resulted in a compromise of the integrity of biennial

dynamic simulator examinations had no compensatory actions been taken, the equitable

and consistent administration of the biennial dynamic simulator examination was not

actually affected by this compromise.

The failure of the licensee to meet 10 CFR 55.49 requirements was determined to be a

Severity Level IV (SL-IV) violation. This is based on the failure to fully delete trend

parameter and range information from the simulated plant computer being a non-willful

compromise of an examination required by 10 CFR Part 55, that did not contribute to the

NRC making an incorrect regulatory decision. This is consistent with Section 2.2.4 and

Section 6.4.d of the NRC Enforcement Policy (issued June 7, 2012).

- 16 -

This finding has a cross-cutting aspect in the resources component of the human

performance cross-cutting area because the licensee failed to ensure the procedures

are adequate to ensure nuclear safety. After a licensee procedure review was

conducted, the licensee concluded that a programmatic issue existed in that the

simulator examination security checklist in TQ2.ID4, Training Program Implementation,

did not provide sufficient information to ensure the simulated plant computer was fully

cleared of plant trend parameters and range [H.1].

Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) 55.49, Integrity of

Examinations, requires, in part, that facility licensees shall not engage in any activity

that compromises the integrity of any application, test, or examination. The integrity of a

test or examination is considered compromised if any activity, regardless of intent,

affected or, but for detection, would have affected the equitable and consistent

administration of the test or examination. Contrary to the above, from 2008 to

May 26, 2015, the licensee engaged in an activity that compromised the integrity of the

examination administered on May 26, 2015. Specifically, an operator discovered plan

parameters and range values that the previous crew had established and was able to

determine the likely plant events that were going to be used in simulator examination.

Upon discovery of the compromised examination, the licensee invalidated the scenario

for the affected crew and administered an alternate scenario.

The inspectors determined that the compromise of the 2015 biennial simulator

examination did not result in an actual effect on the equitable and consistent

administration of the examination. Because this finding is of very low safety

significance and has been entered into the licensees corrective action program

as Notification 50704195 to address recurrence, this violation is being treated as a

non-cited violation consistent with Section 2.3.2 of the NRC Enforcement Policy:

NCV 05000275/2015002-02; 05000323/2015002-02, Failure to Maintain Operator

Licensing Examination Integrity.

1R12 Maintenance Effectiveness (71111.12)

a. Inspection Scope

The inspectors reviewed three instances of degraded performance or condition of

safety-related structures, systems, and components (SSCs):

• April 18-22, 2015, Unit 2, emergency diesel generator (2-2) programmable

controller timer failure

• April 20-22, 2015, Unit 2, emergency diesel generator cap screws replacement

• June 30, 2015, 230 kV and 500 kV equipment reliability activities

The inspectors reviewed the extent of condition of possible common cause SSC failures

and evaluated the adequacy of the licensees corrective actions. The inspectors

reviewed the licensees work practices to evaluate whether these may have played a

role in the degradation of the SSCs. The inspectors assessed the licensees

characterization of the degradation in accordance with 10 CFR 50.65 (the Maintenance

Rule), and verified that the licensee was appropriately tracking degraded performance

and conditions in accordance with the Maintenance Rule.

- 17 -

These activities constituted completion of three maintenance effectiveness samples, as

defined in Inspection Procedure 71111.12.

b. Findings

No findings were identified.

1R13 Maintenance Risk Assessments and Emergent Work Control (71111.13)

a. Inspection Scope

The inspectors reviewed three risk assessments performed by the licensee prior to

changes in plant configuration and the risk management actions taken by the licensee in

response to elevated risk:

• April 28-30, 2015, Unit 1 and 2, 230 kV switchyard activities for planned

maintenance on high voltage insulators and site startup power

• May 11, 2015, Unit 2, auxiliary salt water screen replacement

• June 29, 2015, Unit 2, emergency diesel generator 2-2 planned maintenance

The inspectors verified that these risk assessment were performed timely and in

accordance with the requirements of 10 CFR 50.65 (the Maintenance Rule) and plant

procedures. The inspectors reviewed the accuracy and completeness of the licensees

risk assessments and verified that the licensee implemented appropriate risk

management actions based on the result of the assessments.

The inspectors also observed portions of three emergent work activities that had the

potential to cause an initiating event, or to affect the functional capability of mitigating

systems:

• April 22-23, 2015, Unit 1 and 2, clearance of carbon dioxide fire suppression

system for hose reel replacement

• May 20, 2015, Unit 2, power operated relief valve downstream tailpipe

temperature setpoint change

• June 21-22, 2015, Unit 1, emergency diesel generator 1-2 planned maintenance

The inspectors verified that the licensee appropriately developed and followed a work

plan for these activities. The inspectors verified that the licensee took precautions to

minimize the impact of the work activities on unaffected structures, systems, and

components (SSCs).

These activities constitute completion of six maintenance risk assessments and

emergent work control inspection samples, as defined in Inspection Procedure 71111.13.

b. Findings

No findings were identified.

- 18 -

1R15 Operability Determinations and Functionality Assessments (71111.15)

a. Inspection Scope

The inspectors reviewed six operability determinations that the licensee performed for

degraded or nonconforming structures, systems, or components (SSCs):

• April 1-3, 2015, operability determination of Unit 1, plant vent normal range

radiation monitor RM-24, incorrect input to source term data to emergency plan

management system

• April 6-8, 2015, operability determination of Unit 2, auxiliary feedwater pump 2-3,

discharge header piping wear

• April 16-17, 2015, operability determination of reactor coolant leak detection

monitoring

• April 23, 2015, Unit 2, operability determination of high pressure turbine reheat

steam leakage

• May 18, 2015 Unit 2 operability determination of pressurizer relief tank

pressurization

• May 26, 2015, operability determination of emergency diesel generator hurricane

barrier corrosion

The inspectors reviewed the timeliness and technical adequacy of the licensees

evaluations. Where the licensee determined the degraded SSC to be operable, the

inspectors verified that the licensees compensatory measures were appropriate to

provide reasonable assurance of operability. The inspectors verified that the licensee

had considered the effect of other degraded conditions on the operability of the

degraded SSC.

These activities constitute completion of six operability and functionality review samples,

as defined in Inspection Procedure 71111.15.

b. Findings

No findings were identified.

1R18 Plant Modifications (71111.18)

a. Inspection Scope

The inspectors reviewed two temporary plant modifications that affected risk-significant

structures, systems, and components (SSCs):

• May 12, 2015, Unit 1, auxiliary salt water system screen replacement

• May 20, 2015, Unit 2, power operation relief valve downstream tailpipe

temperature setpoint change

- 19 -

The inspectors verified that the licensee had installed these temporary modifications in

accordance with technically adequate design documents. The inspectors verified that

these modifications did not adversely impact the operability or availability of affected

SSCs. The inspectors reviewed design documentation and plant procedures affected by

the modifications to verify the licensee maintained configuration control.

These activities constitute completion of two samples of temporary modifications, as

defined in Inspection Procedure 71111.18.

b. Findings

No findings were identified.

1R19 Post-Maintenance Testing (71111.19)

a. Inspection Scope

The inspectors reviewed five post-maintenance testing activities that affected

risk-significant structures, systems, or components (SSCs):

• April 30, 2015, Unit 1, pressurizer heater group 1-2 supply breaker and control

switch maintenance testing description

• May 12-13, 2015, Unit 1 and 2, test of diesel fuel oil transfer pump following

transfer switch maintenance

• May 19, 2015, Unit 1, auxiliary salt water system following screen replacement

• May 27-28, 2015, Unit 1, containment cooling unit fan 1-5 relay replacement

• June 30, 2015, Unit 2, emergency diesel generator following maintenance

The inspectors reviewed licensing- and design-basis documents for the SSCs and the

maintenance and post-maintenance test procedures. The inspectors observed the

performance of the post-maintenance tests to verify that the licensee performed the tests

in accordance with approved procedures, satisfied the established acceptance criteria,

and restored the operability of the affected SSCs.

These activities constitute completion of five post-maintenance testing inspection

samples, as defined in Inspection Procedure 71111.19.

b. Findings

No findings were identified.

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1R22 Surveillance Testing (71111.22)

a. Inspection Scope

The inspectors observed six risk-significant surveillance tests and reviewed test results

to verify that these tests adequately demonstrated that the structures, systems, and

components (SSCs) were capable of performing their safety functions:

In-service tests:

• April 9, 2015, Unit 1, auxiliary saltwater pump 1-1, comprehensive testing

• May 6, 2015, Unit 2, turbine valve testing

Reactor coolant system leak detection tests:

• May 14, 2015, Unit 2, power operated relief and block valve leakage

determination

Other surveillance tests:

• April 1, 2015, Unit 1, train B, solid state protection system actuation logic and

safety injection reset timer slave relay K602 testing

• April 22, 2015, Unit 1, protection set 3 channel operational test

• May 22-23, 2015, Unit 2, emergency diesel generator 2-2, biennial 24-hour load

and hot test

The inspectors verified that these tests met technical specification requirements, that the

licensee performed the tests in accordance with their procedures, and that the results of

the test satisfied appropriate acceptance criteria. The inspectors verified that the

licensee restored the operability of the affected SSCs following testing.

These activities constitute completion of six surveillance testing inspection samples, as

defined in Inspection Procedure 71111.22.

b. Findings

No findings were identified.

Cornerstone: Emergency Preparedness

1EP6 Drill Evaluation (71114.06)

Emergency Preparedness Drill Observation

a. Inspection Scope

The inspectors observed an emergency preparedness drill on June 10, 2015, to verify

the adequacy and capability of the licensees assessment of drill performance. The

inspectors reviewed the drill scenario, observed the drill from the Technical Support

Center and Operations Support Center, and reviewed the post-drill critique. The

inspectors verified that the licensees emergency classifications, off-site notifications,

and protective action recommendations were appropriate and timely. The inspectors

verified that any emergency preparedness weaknesses were appropriately identified by

- 21 -

the licensee in the post-drill critique and entered into the corrective action program for

resolution.

These activities constitute completion of one emergency preparedness drill observation

sample, as defined in Inspection Procedure 71114.06.

b. Findings

No findings were identified.

4. OTHER ACTIVITIES

Cornerstones: Initiating Events, Mitigating Systems, Barrier Integrity, Emergency

Preparedness, Public Radiation Safety, Occupational Radiation Safety, and

Security

4OA1 Performance Indicator Verification (71151)

.1 Safety System Functional Failures (MS05)

a. Inspection Scope

For the period of January 1, 2014 through March 31, 2015, the inspectors reviewed

licensee event reports (LERs), maintenance rule evaluations, and other records that

could indicate whether safety system functional failures had occurred. The inspectors

used definitions and guidance contained in Nuclear Energy Institute Document 99-02,

Regulatory Assessment Performance Indicator Guideline, Revision 7, and

NUREG-1022, Event Reporting Guidelines: 10 CFR 50.72 and 50.73, Revision 3, to

determine the accuracy of the data reported.

These activities constituted verification of the safety system functional failures

performance indicator for Units 1 and 2, as defined in Inspection Procedure 71151.

b. Findings

No findings were identified.

.2 Mitigating Systems Performance Index: Emergency AC Power Systems (MS06)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the

period of January 1, 2014 through March 31, 2015, to verify the accuracy and

completeness of the reported data. The inspectors used definitions and guidance

contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported

data.

These activities constituted verification of the mitigating system performance index for

emergency AC power systems for Units 1 and 2, as defined in Inspection

Procedure 71151.

- 22 -

b. Findings

No findings were identified.

.3 Mitigating Systems Performance Index: High Pressure Injection Systems (MS07)

a. Inspection Scope

The inspectors reviewed the licensees mitigating system performance index data for the

period of January 1, 2014 through March 31, 2015, to verify the accuracy and

completeness of the reported data. The inspectors used definitions and guidance

contained in Nuclear Energy Institute Document 99-02, Regulatory Assessment

Performance Indicator Guideline, Revision 7, to determine the accuracy of the reported

data.

These activities constituted verification of the mitigating system performance index for

high pressure injection systems for Units 1 and 2, as defined in Inspection

Procedure 71151.

b. Findings

No findings were identified.

4OA2 Problem Identification and Resolution (71152)

.1 Routine Review

a. Inspection Scope

Throughout the inspection period, the inspectors performed daily reviews of items

entered into the licensees corrective action program. The inspectors verified that

licensee personnel were identifying problems at an appropriate threshold and entering

these problems into the corrective action program for resolution. The inspectors verified

that the licensee developed and implemented corrective actions commensurate with the

significance of the problems identified. The inspectors also reviewed the licensees

problem identification and resolution activities during the performance of the other

inspection activities documented in this report.

b. Findings

No findings were identified.

.2 Semiannual Trend Review

a. Inspection Scope

The inspectors reviewed the licensees corrective action program, performance

indicators, system health reports, and other documentation to identify trends that might

indicate the existence of a more significant safety issue. The inspectors reviewed the

Licensing Basis Verification Project (LBVP) to assess whether this project was

continuing to identify and resolve historical conflicts in the licensing basis

documentation.

- 23 -

These activities constitute completion of one semiannual trend review sample, as

defined in Inspection Procedure 71152.

b. Observations

The LBVP is a significant initiative that PG&E committed to the NRC in order to identify

and resolve numerous historical conflicts in the licensing basis documentation. The

licensees expansion of the LBVP to include reviewing the licensing bases of Diablo

Canyons Emergency Preparedness Program to identify weaknesses and potential non-

conformances is appropriate in light of the White finding (Final Significance

Determination of White Finding and Notice of Violation; Diablo Canyon Nuclear Power

Plant - NRC Emergency Preparedness Inspection Report 05000275/2015502 and

05000323/2015502). At the close of the inspection period, the licensee had not

completed the project.

c. Findings

No findings were identified.

.3 Annual Follow-up of Selected Issues

a. Inspection Scope

The inspectors selected one issue for an in-depth follow-up:

• May 29, 2015, Unit 2, power operated relief valve and block valve leakage

The inspectors assessed the licensees problem identification threshold, cause analyses,

extent of condition reviews and compensatory actions. The inspectors verified that the

licensee appropriately prioritized the planned corrective actions and that these actions

were adequate to for continued operation with degraded valves in accordance with

technical specification requirements.

These activities constitute completion of one annual follow-up sample as defined in

Inspection Procedure 71152.

b. Findings

No findings were identified.

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.4 Selected Issue Follow-up Inspection

a. Inspection Scope

The inspectors reviewed the licensees fire barrier, doors and high-energy line break

(HELB) program including the corrective action program to identify trends that might

indicate the existence of a more significant safety issue. The inspectors verified that the

licensee was taking corrective actions to address identified adverse trends related to fire

doors and barriers. Specifically, the inspectors noted that signage on doors were

missing and not correct.

These activities constitute completion of one semiannual trend review sample, as

defined in Inspection Procedure 71152.

b. Observations

The inspectors completed numerous plant inspections during the first half of 2015

evaluating fire doors and barriers. The inspectors also reviewed the licensee high

energy line break program which is integral to the licensee fire door program. Following

several observations by the inspectors it was identified that some HELB vent flow paths

were being obstructed. The licensee took immediate actions to remove the obstruction

and remove erroneous door signs.

c. Findings

Introduction. The inspectors identified a Green, non-cited violation of 10 CFR Part 50,

Appendix B, Criterion III, Design Control, involving the licensees failure to ensure

credited design features, such as flow vent paths, protect safety-related systems, from

temperature and pressure effects of a HELB in the auxiliary building. Specifically, the

licensee allowed obstruction of a credited flow path with acrylic glass plates not qualified

in the original design and not verified to function under a HELB scenario.

Description. On April 16, 2015, the inspectors, on a plant tour in the auxiliary building,

observed various fire protection doors were not consistently labelled. In addition, the

inspectors noted certain HELB vent-type doors, such as grated doors to letdown and

seal injection heat exchanger rooms, were designated as vent paths. These vent path

doors, located on the 85 foot elevation, were specifically designed with grated-style

panels so a continuous vent path is maintain between rooms in the auxiliary building.

The door signage on these vent path doors was incorrect because it stated that the

grated door was a HELB boundary door and should remain closed. However, the

inspectors found the doors open. The inspectors also identified that all of the

grated-style doors to rooms in the auxiliary building were covered with one-quarter-inch

thick acrylic glass plates that were firmly attached to the grating with plastic tie-wraps.

The inspectors reported these issues and requested additional information regarding the

engineering analysis that allowed the grated doors, a credited design vent path, to be

blocked with acrylic glass plates. The inspectors concerns with incorrect signage were

documented in Notification 50697910, and concerns regarding the blocked HELB vent

doors were documented in Notification 50698102. Immediate actions were taken to

remove the acrylic glass plates and incorrect signage from the vent path doors in the

auxiliary building.

- 25 -

On April 20, 2015, the inspectors concerns were evaluated further in

Notification 50698455. The licensee response identified that a design change was

added using design change package DCP M-49919, dated November 27, 2007. Part of

this design change establishes the potential reduction of HELB compartment vent flow

areas due to panel installations at the grated doors but assumed grated door were

covered with plastic sheets. The design change assumed these plastic sheets would

blow off during a HELB event. However, the licensee analysis on covering and blocking

the grated vent doors was qualitative and did not describe specific requirements and

limitations for the plastic sheets. On July 6, 2015, the licensee identified the equipment

functional location information contained in the design technical notes was erroneous.

Notification 50710846 documented this as a contributing factor for allowing a door

configuration outside the design requirements. The technical note, dated

October 5, 2007, states, in part, it is acceptable to have a plastic cover on this doors.

The note also refers to a design change and evaluation which was determined to be

inadequate.

The inspectors determined DCPP FSAR Update, Revision 22, Section 3.6.4.3,

High-Energy Piping Breaks Outside Containment, and Section 3.11, Environmental

Design of Mechanical and Electrical Equipment, provides design requirements to

protect safety-related structures, systems and components (SSCs) from the dynamic

effects of a HELB and the equipment qualification requirements for SSCs in a harsh

environment. In addition, pressurization of compartments with grated doors was part of

the analysis and was included in design calculation M-493, Areas H & K Pressures and

Temperatures in Auxiliary Building due to Pipe Breaks. Following a HELB, the rapid

introduction of steam increases the pressure and temperature in the compartment.

These conditions will propagate from the break through available flow paths. The

inspectors determined that the safety function of the grated doors, as a credited flow

path out of the heat exchanger rooms and to relieve the break flow and maintain

pressure and temperature, was actually invalidated by the obstruction of acrylic glass

plates.

Because of the inspectors concerns on the adequacy of the design, the licensee

performed a past operability evaluation which was documented in Notification 50698455.

The licensee identified: The [HELB] analysis was potentially invalidated by obstructions

on two credited flow paths out of the heat exchanger room (Doors 176A&B (U1) and

Doors 184A&B (U2)). Although placing plastic sheet on the outside of these doors was

evaluated to blow out by engineering judgement, there were no design details that

provided design requirements or limitations.

The inspectors determined that, in November 2007, engineering judgement was used

that allowed the grated doors to be obstructed with plastic tarp materials; it was judged

to be acceptable, but the inspectors determined that a qualified engineering analysis

was not done for placement of the one-quarter-inch thick acrylic glass plates using

plastic tie-wraps.

On May 13, 2015, because of the inspectors concerns, the licensee performed

extensive in-situ testing and determined that acrylic covers held with plastic tie-wraps

would not have invalidated the HELB analysis found in design calculations M-493.

- 26 -

Analysis. The inspectors determined that the failure to ensure credited design features,

such as flow vent paths, protect safety-related systems, from temperature and pressure

effects of a HELB in the auxiliary building was a performance deficiency. The

performance deficiency was determined to be more than minor because it affected the

Mitigating Systems Cornerstone attribute of Design Control and adversely affected the

cornerstone objective of ensuring the reliability, availability and capability of systems that

respond to initiating events to prevent undesirable consequences. Specifically, the

licensee did not have adequate measures in place to ensure that qualified components

were available to mitigate the consequences of a HELB in the auxiliary building

Using IMC 0609, Appendix A, issued June 19, 2012, The Significance Determination

Process (SDP) for Findings At-Power, the inspectors determined that the finding was of

very low safety significance (Green) because the finding did not affect the design or

qualification of mitigating structures, systems, and components; the finding did not

represent a loss of system and/or function; the finding did not represent an actual loss of

a function of a single train for greater than the technical specification (TS) allowed

outage time; the finding did not represent an actual loss of a function of one or more

non-TS trains of equipment; and did not screen as potentially risk-significant due to a

seismic, flooding, or severe-weather initiating event. Specifically, the licensee performed

an analysis that concluded the environmental qualifications of the safety-related

equipment in the auxiliary building would not be exceeded by a HELB in the auxiliary

building.

The finding was not assigned a cross-cutting aspect since the performance deficiency is

not indicative of current plant performance.

Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) Part 50,

Appendix B, Criterion III, Design Control, requires, in part, that design control

measures shall provide for verifying or checking the adequacy of design, such as by the

performance of design reviews, by the use of alternate or simplified calculational

methods, or by performance of a suitable testing program. Contrary to the above, from

November 27, 2007, until April 20, 2015, Design Calculation Package C-47451 used

non-conservative assumptions, which did not appropriately verify the obstruction to

HELB compartment vent flow path would have maintained the environmental

qualification of safety-related equipment in the auxiliary building. The licensee validated

the condition by performing an in-situ analysis of the glass plate and tie-wraps in order to

determine whether the acrylic glass panels would have blown off during a HELB and,

therefore, would not have resulted in impact to environmental qualification assumptions.

Because this finding is of very low safety significance (Green) and was entered into the

licensees corrective action program as Notification 50698455, this violation is being

treated as a non-cited violation consistent with Section 2.3.2.a of the NRCs

Enforcement Policy: NCV 05000275/2015002-03; 05000323/2015002-03, Inadequate

Design Control for High-Energy Line Break Vent Flow Path.

4OA3 Follow-up of Events and Notices of Enforcement Discretion (71153)

.1 (Closed) Licensee Event Report (LER) 05000275; 05000323/2014-003-02: Unanalyzed

Condition Affecting Unit 1 and 2 Emergency Diesel Generators, Tornado Missiles

On March 6, 2014, as part of the LBVP, the licensee identified an unanalyzed condition

where the EDG exhaust plenums and exhaust piping were not adequately protected

- 27 -

from tornado missiles. This is a nonconforming condition with DCPP licensing basis

requirements. The licensee reported this unanalyzed condition to the NRC in Event

Notification Number 49879. Subsequent questions from the NRC resident inspector

prompted an evaluation of the DCPP licensing basis for tornado missiles. This

evaluation identified that the licensing basis requirements for EDG ventilation systems

and exhaust pipes require protection from tornado missiles.

The inspectors dispositioned the unanalyzed condition as a Green finding in

Section 1R15 of NRC Integrated Inspection Report 05000275/2014002 and

05000323/2014002.

No additional deficiencies were identified during the review of this licensee event report.

This licensee event report is closed.

.2 (Closed) LER 05000275; 05000323/2012-005-01: Unanalyzed Condition due to

Nonconservative Change in Atmospheric Dispersion Factor

On July 5, 2012, as part of the LBVP, the licensee identified a non-conservative change

in the DCPP Final Safety Analysis Report Update (FSARU) Chapter 15, "Accident

Analyses," control room atmospheric dispersion factor (X/Q) methodology, made in

Revision 2 of the DCPP FSARU in 1986. The cause of this event was determined to be

an inadequate design control process in 1986, whereby the analysis change was made

without evaluating the change in accordance with 10 CFR 50.59 to determine whether or

not prior NRC review and approval was required. The corrective actions included:

(1) revising the X/Qs used in the analyses and incorporating them into the DCPP

licensing basis, and (2) submitting License Amendment Request 15-03 on

June 17, 2015, to request approval from the NRC to adopt the alternate source term as

allowed by 10 CFR 50.67.

The inspectors dispositioned the unanalyzed condition as a Green finding in

Section 1R15 of NRC Integrated Inspection Report 05000275/2012005

and 05000323/2012005.

No additional deficiencies were identified during the review of this licensee event report.

This licensee event report is closed.

.3 (Closed) LER 05000275/2013-008-00: Technical Specification 3.3.4 Not Met Due to

Inoperable Remote Shutdown System Function

a. Inspection Scope

The inspectors checked the accuracy and completeness of the LER and the

appropriateness of the licensees corrective actions. The licensee failed to properly

reinstall fuses that affected local manual operation of emergency diesel generator

(EDG) 1-3.

b. Findings

Introduction. The inspectors reviewed a self-revealing Green, non-cited violation of

Technical Specification 3.3.4 Remote Shutdown System, for the licensees failure to

- 28 -

maintain adequate configuration control of fuses associated with an EDG. The licensee

failure to maintain adequate configuration control by not verifying that fuses were

properly installed, and adequate post maintenance testing was performed, following

maintenance activities was a performance deficiency. Specifically, following the 1R17

refueling outage from approximately June 13, 2013 until November 22, 2013, EDG 1-3

would not have been able to perform its remote shutdown function due to not being able

to be adequately operated at the local EDG control cubicle.

Description. On November 19, 2013, DCPP maintenance technicians were conducting

relay testing on EDG 1-3 Output Breaker 52HF7, and discovered the breaker could not

be closed locally. Maintenance personnel found the US fuses in the 52HF7 cubicle in

the OFF position. With the US fuses in the OFF position, operators would not be able to

close EDG 1-3 output breaker at the breaker cubicle unless they opened the breaker

cubicle and manually closed the breaker. This manual operation was not

proceduralized, so successful performance of this task could not be guaranteed. Local

breaker closure capability is required to satisfy Technical Specification 3.3.4 remote

shutdown functionality in the event operation from the control room is not available.

Licensee personnel determined the US fuses in the 52HF7 cubicle were installed during

refueling outage maintenance activities in the incorrect position, and therefore failed to

maintain adequate configuration control of the EDG remote shutdown function as

required by technical specifications. Maintenance technicians restored the US fuses to

the correct position on November 22, 2013, and verified the positions of the US fuses in

the other EDG output breaker cubicles.

Licensee personnel determined that a human error by vendor maintenance technicians

was the most probable cause. A failure to maintain adequate configuration control of the

US fuses in the 52HF7 cubicle following the Unit 1 Refueling Outage 17 maintenance

activities most likely allowed the fuses to be reinstalled in the incorrect position.

Licensee personnel additionally determined that return to service testing following

maintenance activities was inadequate, in that it did not verify remote shutdown

functionality.

Analysis. The failure to properly install fuses in the local manual operation circuitry of

EDG 1-3 was a performance deficiency. The performance deficiency was more than

minor because it was associated with the protection against external events (fire)

attribute of the Mitigating Systems Cornerstone, and it adversely affected the

cornerstone objective of ensuring the availability, reliability, and capability of systems

that respond to initiating events to prevent undesirable consequences. Specifically, it

affected the ability to reach and maintain safe shutdown conditions in case of a fire

causing a control room abandonment. The inspectors evaluated this finding using

Inspection Manual Chapter 0609, Appendix F, Fire Protection Significance

Determination Process," dated September 20, 2013. Because it affected the ability to

reach and maintain safe shutdown conditions in case of a fire that led to control room

evacuation, the Phase 2 methodology of Inspection Manual Chapter 0609, Appendix F,

was not appropriate for this finding. Therefore, the senior reactor analyst performed a

Phase 3 evaluation to determine the risk significance.

The analyst determined that the performance deficiency only increased the risk of the

plant as it related to the need to locally control EDG 1-3 following a postulated control

room evacuation. The analyst reviewed Abnormal Operating Procedure OP AP-8A,

Control Room Inaccessibility - Establishing Hot Standby, and determined that EDG 1-3

- 29 -

was only needed in the event of a control room evacuation that also included a loss of

offsite power. According to plant procedures, control room evacuations could be

initiated by fires in either the main control room or the cable spreading room.

The Senior Risk Analyst determined that the change in core damage frequency was less

than 1 x 10-6 and the finding was not significant with respect to large, early release

frequency. In accordance with the guidance in Inspection Manual Chapter 0609,

Appendix H, Containment Integrity Significance Determination Process, dated

May 6, 2004, the senior reactor analyst screened the performance deficiency for its

potential risk contribution to large early release frequency because the bounding change

in core damage frequency provided a risk significance estimate greater than 1 x 10-7 per

year. Given that DCPP has a large, dry containment and that control room evacuation

sequences do not include steam generator tube ruptures or intersystem loss of coolant

accidents, the analyst determined that this finding was not significant with respect to

large, early release frequency. Therefore, the analyst determined that this finding was of

very low risk significance (Green).

This finding had a cross-cutting aspect in the area of human performance associated

with the work practices component, because the licensee did not ensure supervisory and

management oversight of work activities, such that nuclear safety was supported [H.5].

Enforcement. Technical Specification 3.3.4 Remote Shutdown System, requires, in

part, that the EDG control function to be operable in modes 1, 2 and 3. Contrary to the

above, from June 13, 2013 until November 22, 2013, the licensee failed to ensure the

remote shutdown function was available. As a result, the availability of EDG 1-3 could

have been adversely impacted if the remote shutdown function was required. Because

the licensee entered the issue into its corrective action program as

Notification 50595473, and the finding is of very low safety significance (Green), this

violation is being treated as a non-cited violation, consistent with Section 2.3.2 of the

NRC Enforcement Policy: NCV 05000275/2015002-04, Technical Specification 3.3.4

Not Met Due to Inoperable Remote Shutdown System Function.

This licensee event report is closed.

.4 (Closed) LER 05000275; 05000323/1-2014-004-00 and -01: Actuation of Six

Emergency Diesel Generators due to Loss of Offsite Power

a. Inspection Scope

On October 31, 2014, during a medium to heavy rain, the 230 kV offsite power source at

Diablo Canyon was lost due to an insulator flashover in the 230 kV switchyard resulting

in a valid actuation of all Unit 1 and 2 EDGs. As a result, the primary offsite power

source was lost, but the safety-related EDGs were available to provide vital buses if

there was a loss of main auxiliary buses.

b. Findings

(1) Introduction. The inspectors identified a Green, non-cited violation of

10 CFR 50.65(b)(2) for the licensees failure to appropriately scope the 230 kV

switchyard in the maintenance rule monitoring program. Specifically, from the inception

of the facilities monitoring program through May 18, 2015, the licensee failed to properly

- 30 -

scope or evaluate the 230 kV switchyard to include the entire switchyard up through the

first inter-tie circuit breakers CB262 and CB282 into the Maintenance Rule program.

Electrical faults within the 230 kV switchyard can cause loss of offsite power which is

relied upon to mitigate accidents and cause an actuation of a safety-related systems,

such as, EDGs, and should have been included into its Maintenance Rule program.

This issue was entered into the licensees corrective action program as Notifications

50702970 and 50703118.

Description. On April 28, 2015, during their review of the licensees root cause

investigation into the 230 kV flashover and loss of startup power documented in

Notification 50669932, the inspectors identified that this event had occurred while the

230 kV switchyard was in Maintenance Rule (a)(1) maintenance monitoring status. The

inspectors identified concerns related to the Maintenance Rule evaluation of the 230 kV

switchyard electrical distribution equipment. Following their evaluation, the inspectors

determined that the licensee had failed to appropriately scope the 230 kV offsite power

source to include the entire switchyard up through the first inter-tie circuit breakers

CB262 and CB282.

The inspectors determined the maintenance activities that occur in the switchyard can

directly affect plant operations and electrical components out to the first inter-tie circuit

breakers and therefore should have been considered for inclusion in the Maintenance

Rule. The following NRC requirements were reviewed by the inspectors:

Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b) specifies:

(b) The scope of the monitoring program specified in paragraph (a)(1) of this section

shall include safety-related and non-safety-related structures, systems, and

components (SSCs), as follows:

(1) Safety-related SSCs that are relied upon to remain functional during and following

design basis events to ensure the integrity of the reactor coolant pressure boundary,

the capability to shut down the reactor and maintain it in a safe shutdown condition,

or the capability to prevent or mitigate consequences of accidents that could result in

potential offsite exposure comparable to the guidelines in Sec. 50.34(a)(1),

Sect. 50.67(b)(2), or sec. 100.11 of this chapter, as applicable.

(2) Non-safety-related structures, systems, or components:

(i) That are relied upon to mitigate accidents or transients or are used in plant

emergency operating procedures (EOPs); or

(ii) Whose failure could prevent safety-related structures, systems, and

components from fulfilling their safety-related function; or

(iii) Whose failure could cause a reactor scram or actuation of a safety-related

system.

The inspectors determined 10 CFR 50.65(b)(2) items (i) and (iii) are applicable for the

DCPP 230 kV offsite power source including the switchyard up through the first breakers

from the transmission system. Specifically, electrical faults within the 230 kV switchyard

can cause loss of offsite power which is relied upon to mitigate accidents and cause an

actuation of safety-related systems, such as EDGs. Inspectors discussed these results

- 31 -

with the Office of Nuclear Reactor Regulation (NRR), and NRR staff acknowledged the

issues and concurred on this inspection conclusion. In response to the inspectors

concerns, the licensee initiated Notification 50703118 to evaluate the need to include the

230 kV switchyard into its Maintenance Rule program. On May 18, 2015, following

discussions with inspectors, the licensee completed an evaluation of the maintenance

rule program and documented in Notification 50702970, the following conclusion:

A 230 kV switchyard bus fault of either Bus 1 or Bus 2 can cause a loss of the entire

230 kV switchyard as the bus fault will cause all switchyard breakers to open to clear

the bus fault. This type of event would cause a loss of function for which the 230 kV

system is scoped into the Maintenance Rule.

The licensee also concluded the Maintenance Rule scoping for the 230 kV offsite power

source failed to include the switchyard out to the offsite inter-tie breakers or up through

the first breakers from the transmission system.

Analysis. The inspectors determined that the licensees failure to scope the 230 kV

offsite power source including the switchyard up through the first breakers from the

transmission system into the Maintenance Rule program was contrary to the

requirements of 10 CFR 50.65 and therefore a performance deficiency. The

performance deficiency was determined to be more than minor because it is associated

with the initiating events attribute of protections against external factors and adversely

affected the cornerstone objective, in that, a 230 kV switchyard failure can upset plant

stability and challenge critical safety functions during shutdown as well as power

operations. Failure to monitor the performance or condition of 230 kV offsite power

source (including the switchyard up through the first breakers from the transmission

system) in a manner sufficient to provide reasonable assurance the offsite power was

capable of fulfilling the intended functions affected the reliability of the plant equipment to

perform their safety function.

The inspectors determined that had the 230 kV switchyard been properly scoped into the

Maintenance Rule program, the loss of offsite power due to the flash over event may

have been prevented. However the direct cause of the event was identified as untimely

corrective actions associated with an ineffective corrective action program. As such,

improper Maintenance Rule scoping was not the direct cause. Therefore, the inspectors

determined the finding could be evaluated using the significant determination process in

accordance using IMC 0609, Appendix A, Significance Determination Process (SDP) for

Findings At-Power, Exhibit 1, Initiating Events Screening Questions. The inspectors

determined that the finding was of very low safety significance (Green) because the

finding was determined not to be the cause of the actual 230 kV failure such that all of

the screening questions in Exhibit 1 could be answered no.

The inspectors determined that since the scoping of the switchyard systems had

occurred more than 3 years ago, and the opportunity to reevaluate system scoping had

not recently occurred, the finding did not represent current licensee performance and

therefore a cross-cutting aspect was not assigned.

Enforcement. Title 10 of the Code of Federal Regulations (10 CFR) 50.65(b)(2)

requires, in part, that the scope of the monitoring program specified in paragraph (a)(1)

of 10 CFR 50.65 shall include non-safety-related SSCs whose failure could prevent

safety-related SSCs from fulfilling their safety-related function. Contrary to the above,

from the inception of the facilities monitoring program through May 18, 2015, the

- 32 -

licensee failed to include a non-safety-related system and component whose failure

could prevent safety-related SSCs from fulfilling their safety-related functions in a

maintenance monitoring program. Specifically, the inspectors identified the 230 kV

offsite power source, including the switchyard up through the first inter-tie circuit

breakers, were not included in the maintenance monitoring program. Because this

violation was of very low safety significance and it was entered into the licensees

corrective action program as Notifications 50702970 and 50703118, this violation is

being treated as a non-cited violation, consistent with Section 2.3.2 of the NRC

Enforcement Policy: NCV 05000275/2015002-05; 05000323/2015002-05, Failure to

Appropriately Scope 230 kV Switchyard into the Maintenance Rule Monitoring Program.

(2) Introduction: The inspectors reviewed a self-revealing, Green finding for the licensees

failure to adequately implement procedure OM7.ID1, Problem Identification and

Resolution, to prevent a high voltage insulator flashover event in the 230 kV switchyard

that occurred on October 31, 2014. Specifically, corrective actions from three previous

root cause evaluations were not effective to prevent a loss of the 230 kV start-up power

and subsequent auto start of all of the safety standby EDGs.

Description: As documented in the licensees corrective action program trending

process, the licensee recognized increased susceptibilities to high-voltage insulator

flashovers were attributed to inadequate high voltage insulation design and preventative

maintenance strategies at Diablo Canyon. Over an extended period, the licensee

evaluated numerous high-voltage insulation failures, starting in August 2008, when

Unit 2 main bank transformer C-phase experienced a failure of the high voltage bushing.

The licensees corrective actions for the 2008 event included changes to bushing

materials to prevent reoccurrence. On October 11, 2012, the A-phase high voltage

insulator flashed over in light rain, which resulted in a Unit 2 reactor trip from full power.

Subsequent root cause evaluations recognized concerns with heavy contamination

deposition rates on high-voltage insulators. On June 23, 2013, during heavy fog,

multiple high voltage flashover events were experienced in the offsite switchyard in

Morro Bay, resulting in loss of 230 kV startup power to Diablo Canyon. Again, the

license recognized combined contamination levels and weather were factors in this

event. On July 10, 2013, hot washing of the Unit 2, high voltage insulators resulted in

overspray that caused the Unit 2 A-phase high-voltage insulator on the lightening

arrestor flashover. Because of these numerous high voltage insulator flashover events

the licensee conducted a common cause evaluation and implemented long term

corrective changes to high voltage insulators to increase design margin. On February 2,

2014, during light rain, another flashover of a Unit 2, B-phase high voltage insulator,

resulted in a Unit 2 reactor trip. As a result, interim corrective actions included

cleaning/washing lightning arrestors and high voltage insulators every three months.

Furthermore, on September 18, 2014, arcing in the 230 kV switchyard at Diablo Canyon

was observed. In that event, it was determined that cleaning of susceptible high-voltage

insulators in the switchyard was limited and was not completed on all of the 230 kV

switchyard high-voltage insulators.

However, an opportunity to clean the remaining high-voltage insulators was missed on

October 29, 2014. As a result three days later, on October 31, 2014, during heavy

rainfall, a high-voltage insulator flashover occurred in the Diablo Canyon 230 kV

switchyard resulting in a loss of startup power and subsequent start of all safety-related

EDGs.

- 33 -

Analysis: The licensees failure to adequately implement station procedure OM7.ID1,

Problem Identification and Resolution was a performance deficiency. The performance

deficiency was more than minor because it was associated with the human performance

attribute of the Initiating Events cornerstone and affected the cornerstone objective to

limit the likelihood of those events that upset plant stability and challenge critical safety

functions. Specifically, this failure resulted in another high-voltage insulator flashover,

which resulted in loss of 230 kV offsite startup power and activation of all safety-related

EDGs, on October 31, 2014.

Unit 1 Risk Impact

In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors

determined that the impact of the finding on Unit 1 should be evaluated using Exhibit 1 of

IMC 0609, Appendix A, The Significance Determination Process (SDP) for Findings at

Power, because all questions in Table 3, SDP Appendix Router, were answered NO

directing the user to Appendix A. The inspectors determined that this finding required a

detailed risk evaluation by the regional senior risk analyst because the finding involved a

partial loss of 230 kV offsite power, a support system that contributes to the likelihood of

an initiating event (loss of offsite power) and affected mitigation equipment (EDGs).

The risk analyst determined that, with the 230 kV system deenergized, any plant

transient would result in a plant-centered loss of offsite power. Therefore, the

incremental conditional core damage probability (ICCDP) can be calculated as follows,

given the exposure period (EXP), the conditional core damage probability (CCDP) and

the total transient initiation frequency (Trans):

ICCDP = Trans * CCDP * EXP

The analyst utilized the Standardized Plant Analysis Risk (SPAR) Model for Diablo

Canyon Units 1 & 2, Version 8.23 to calculate the total Trans of 1.1775/year. Additionally,

the analyst quantified the SPAR for a plant-centered loss of offsite power to obtain the

CCDP of 1.73 x 10-4. Given that the 230 kV support system was unavailable from 17:40

on October 31, 2014 until 02:29 on November 1, 2014, the total exposure period was

approximately 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br />. The analyst then calculated the ICCDP as follows:

ICCDP = 1.18/year * 1.73 x 10-4 * 9 hours1.041667e-4 days <br />0.0025 hours <br />1.488095e-5 weeks <br />3.4245e-6 months <br /> ÷ 8760 hour0.101 days <br />2.433 hours <br />0.0145 weeks <br />0.00333 months <br />s/year

= 2.09 x 10-7

Given that the incremental conditional core damage probability is less than the 1 x 10-6

threshold in the significance determination process, this finding is of very low safety

significance (Green) for Unit 1.

Unit 2 Risk Impact

In accordance with IMC 0609.04, Initial Characterization of Findings, the inspectors

determined that the impact of the finding on Unit 2 should be evaluated using IMC 0609,

Appendix G, Shutdown Operations Significance Determination Process, because the

finding pertained to operations, an event, or a degraded condition while the plant was

shut down. Unit 2 was shutdown in a refueling outage when the event occurred on

October 31, 2014. Appendix G is used to evaluate findings that: (1) increase the

likelihood or cause an event, or (2) affect the ability to mitigate an event. Because of the

- 34 -

shutdown configuration of Unit 2, the loss of the 230 kV support system did not impact

the ability to continue to provide decay heat removal for the unit. The only direct effect

on the unit was the anticipatory start of the three Unit 2 diesel generators. Therefore,

the analyst determined qualitatively that this finding is also of very low safety significance

(Green) for Unit 2.

This finding has a cross-cutting aspect of work management, in the area of human

performance, for failing to implement a process of planning, controlling, and executing

work activities such that nuclear safety is an overriding priority. Specifically the licensee

failed to effectively plan and coordinate preventative maintenance strategies associated

with root causes from previous high-voltage insulators flashover or failures since 2008 to

prevent the loss of offsite 230 kV and the transient on October 31, 2014 [H.5].

Enforcement: This finding does not involve enforcement action because no violation of a

regulatory requirement was identified. The licensee took corrective actions to update

interface requirements for transmission and distribution facilities at Diablo Canyon, and

implement a comprehensive time based preventative maintenance washing program.

The licensee entered this finding into their corrective action program as

Notification 50699230. Because this finding does not involve a violation of regulatory

requirements and is of very low safety or security significance, it is identified as a

FIN 05000275/2015002-06; 05000323/2015002-06, High Voltage Insulator Flashover

Resulted in Loss of 230 kV Offsite Power and Start of Emergency Diesel Generators.

.5 (Closed) Unresolved Item 05000275/2014004-05 Notice of Enforcement

Discretion 14-4-001 for a Loss of Both Required Offsite Power Circuits

a. Inspection Scope

As discussed in detail in Inspection Report 05000275; 05000323/2014004, Section

4OA3.4, the NRC telephonically granted at 3:07 p.m. on August 15, 2014, Notice of

Enforcement Discretion (NOED) 14-4-001 for Pacific Gas & Electric, to allow an

additional 3 hours3.472222e-5 days <br />8.333333e-4 hours <br />4.960317e-6 weeks <br />1.1415e-6 months <br /> to restore compliance with Technical Specification 3.8.1, AC Sources

- Operating, Condition H. However, one of the two inoperable EDGs was restored to

operable status at 6:31 p.m. on August 15, 2014, which was within the original technical

specification required action completion time. Therefore, the additional time granted by

the NOED was no longer necessary. Nonetheless, the inspectors performed a review of

the circumstances associated with the granting of NOED 14-4-001, verified the

licensees oral assertions, including the likely cause and compensatory measures, and

verified the notice of enforcement discretion request was consistent with the staffs policy

and guidance.

b. Findings

No findings were identified.

These activities constitute completion of five event follow-up samples, as defined in Inspection

Procedure 71153.

- 35 -

4OA6 Meetings, Including Exit

Exit Meeting Summary

The inspectors debriefed Ms. Gerfen, Director, Operations Services; Mr. Petersen, Director,

Learning Services; and other members of the licensee's staff of the results of the licensed

operator requalification program inspection on May 21, 2015, and telephonically exited with

Mr. Welsch, Site Vice President, and other staff members on June 16, 2015. The licensee

representatives acknowledged the findings presented. The inspectors asked the licensee

whether any materials examined during the inspection should be considered proprietary. No

proprietary information was identified.

On July 7, and July 28, 2015, the resident inspectors presented the inspection results to Mr.

J. Welsch, Site Vice President, and other members of the licensee staff. The licensee

acknowledged the issues presented. The licensee confirmed that any proprietary information

reviewed by the inspectors had been returned or destroyed.

4OA7 Licensee-Identified Violations

The following Severity Level IV violations were identified by the licensee and are violations of

NRC requirements which meet the criteria of the NRC Enforcement Policy for being

dispositioned as non-cited violations.

.1 Title 10 of the Code of Federal Regulations (10 CFR) 50.9, Completeness and accuracy

of information, Section (a) states, in part, that information required by statute or by the

Commission's regulations, orders, or license conditions to be maintained by the

applicant or the licensee shall be complete and accurate in all material respects.

License Condition 2.C.(5) for Unit 1 and 2.C.(4) for Unit 2, Fire Protection, require, in

part, that the licensee shall implement and maintain in effect all provisions of the

approved fire protection program as discussed in its Final Safety Analysis Report

Update. Final Safety Analysis Report Update Appendix 9.5H, Inspection and Testing

Requirements and Program Administration, addresses control of combustible materials

in Special Consideration E, Combustible Materials in Safety-Related Areas. Special

Consideration E states, in part, Use of combustibles in safety-related areas is to be

strictly controlled and is the responsibility of the area or work supervisor. Specific

controls are delineated in plant procedures. Procedure OM8.ID4, Control of

Flammable and Combustible Materials, provides the specific administrative controls

required to keep bulk transient combustible materials within the plant Fire Hazards

Analysis design basis. Step 5.6.4(i) of Procedure OM8.ID4 requires transient

combustible permits to be walked down by the job supervisor or designee once the

permit is in place and every week thereafter until the transient control permit is removed.

Walk downs are documented and any deficiencies noted on DCPP Form 69-13206,

Procedure OM8.ID4, Attachment 3, Transient Combustible Inspection.

Contrary to the above, on April 8, 2014, June 18, 2014, and July 16, 2014, the licensee

failed to complete the walkdowns for the transient combustible permits required by

procedure though they were documented as completed. Specifically, an employee of

the licensee deliberately documented the completion of the transient combustible permit

inspections (walkdowns) within the radiological control area per Procedure OM8.ID4,

when, in fact, he had not completed the inspections. This caused the licensee to be in

violation of License Conditions 2.C.(5) and 2.C.(4) of licenses DPR-80 and DPR-82,

- 36 -

respectively. This is material to the NRC because the review of transient combustible

permit inspections, and associated records, are reviewed as part of the NRCs

inspection of the licensees fire protection program. The licensee identified the violation,

entered the issue into the corrective action program as Notification 50710885, and took

appropriate corrective actions. These included completing confirmatory walkdowns on

July 16, 2014, of the transient combustible permits in question, and performing an

internal corporate investigation as to the cause. Using Inspection Manual Chapter 0609,

Appendix F, Fire Protection Significance Determination Process, the violation was

determined to be of very low safety significance because the reactors were able to reach

and maintain a safe shutdown condition. Traditional enforcement applied to this finding

because it involved a violation that impacted the regulatory process. Assessing the

violation in accordance with Enforcement Policy, the violation was determined it to be of

Severity Level IV (SL-IV) because it resulted in a condition evaluated by the Significance

Determination Process as having very low safety significance (Enforcement Policy

example 6.1.d.2).

In accordance with Section 2.3.2.a of the Enforcement Policy, and with the approval of

the Director, Office of Enforcement, this issue has been characterized as a non-cited

violation, because (1) the licensee entered the issue into its corrective action program;

(2) the licensee promptly restored compliance after identification of the issue; and (3) the

violation was not repetitive as a result of inadequate corrective action. Additionally,

though the violation was willful, (1) the violation was identified by the licensee; (2) the

violation involved the act of an individual, who would not have been considered a

licensee official with oversight of regulated activities as defined in the Enforcement

Policy; (3) the violation did not involve a lack of management oversight and was the

isolated action of the former employee; and (4) significant remedial action

commensurate with the circumstances was taken by the licensee. (EA-15-040)

.2 Title 10 of the Code of Federal Regulations (10 CFR) 50.74(c) requires, in part, that

licensees shall notify the appropriate Regional Administrator within 30 days of a

permanent disability of a licensed operator as described in 10 CFR 55.25. Contrary to

the above, from 2009 to March 4, 2013, the licensee failed to notify the appropriate

Regional Administrator when a licensed operator was diagnosed with a permanent

disability. The licensee documented this issue in DA 50540600. This violation was

determined to impact the regulatory process and was evaluated using Section 2.2.2 of

the NRC Enforcement Policy. In accordance with Section 6.4.d of the NRC Enforcement

Policy, this violation was determined to be a Severity Level IV violation because of the

failure to report a medical condition that would have required a license restriction to

maintain medical qualifications.

- 37 -

SUPPLEMENTAL INFORMATION

KEY POINTS OF CONTACT

Licensee Personnel

B. Allen, Vice President Nuclear Services

T. Baldwin, Director, Nuclear Site Services

J. Becerra, Supervisor, Exam/Simulator

D. Evans, Director, Security & Emergency Services

R. Fortier, Exam Developer

P. Gerfen, Director of Operation Services

M. Ginn, Manager, Nuclear Emergency Planning

E. Halpin, Sr. Vice President, Chief Nuclear Officer

A. Heffner, NRC Interface, Regulatory Services

J. Hinds, Director, Quality Verification

H. Hamzehee, Manager, Regulatory Services

T. Irving, Manager, Radiation Protection

J. Lyle, Supervisor, Operations Continuing Training

J. MacIntyre, Director of Equipment Reliability

M. McCoy, Regulatory Services, NRC Interface

J. Morris, Senior Advising Engineer

J. Nimick, Station Director

A. Peck, Director, Nuclear Engineering

L. Sewell, Nuclear Radiation Protection Engineer

R. Simmons, Manager, Nuclear Maintenance

A. Warwick, Supervisor, Emergency Planning

J. Welsch, Site Vice President

E. Werner, Manager, Operations Training

M. Wright, Nuclear Engineering, Manager

NRC Personnel

D. Loveless, Senior Reactor Analyst

LIST OF ITEMS OPENED, CLOSED, AND DISCUSSED

Opened and Closed

Failure to Appropriately Pre-plan and Perform Maintenance on

05000275/2015002-01 NCV

Hydrogen Guard Piping (Section 1R05)05000275/2015002-02 Failure to Maintain Operator Licensing Examination Integrity

NCV 05000323/2015002-02 (Section 1R11)05000275/2015002-03 Inadequate Design Control for High-Energy Line Break Vent

NCV 05000323/2015002-03 Flow Path (Section 4OA2.4)

Technical Specification 3.3.4 Not Met Due to Inoperable Remote

05000275/2015002-04 NCV

Shutdown System Function (Section 4OA3.3)05000275/2015002-05 Failure to Appropriately Scope 230 KV Switchyard into the

NCV 05000323/2015002-05 Maintenance Rule Monitoring Program (Section 4OA3.4.b.(1))

A-1 Attachment

Opened and Closed

High Voltage Insulator Flashover Resulted in Loss of 230 kV

05000275/2015002-06

FIN Offsite Power and Start of Emergency Diesel Generators05000323/2015002-06

(Section 4OA3.4.b.(2))

Closed

05000275/2014-003-02 Unanalyzed Condition Affecting Unit 1 and 2 Emergency

LER 05000323/2014-003-02 Diesel Generators, Tornado Missiles (Section 4OA3.1)

05000275/2012-005-01 Unanalyzed Condition due to Nonconservative Change in

LER 05000323/2012-005-01 Atmospheric Dispersion Factor (Section 4OA3.2)

Technical Specification 3.3.4 Not Met Due to Inoperable

05000275/2013-008-00 LER

Remote Shutdown System Function (Section 4OA3.3)

05000275/2014-004-00 Actuation of Six Emergency Diesel Generators due to Loss of

LER 05000323/2014-004-00 Offsite Power (Section 4OA3.4)

05000275/2014-004-01 Actuation of Six Emergency Diesel Generators due to Loss of

LER 05000323/2014-004-01 Offsite Power (Section 4OA3.4)

Notice of Enforcement Discretion 14-4-001 for a Loss of Both

0500275/2014004-05 URI

Required Offsite Power Circuits (Section 4OA3.5)

Section 1R01: Adverse Weather Protection

Procedure

Number Title Revision

CP M-16 Severe Weather 4

Notifications

50696079 50696186

Section 1R04: Equipment Alignment

Procedure

Number Title Revision

OP1.DC20 Sealed Components 20

OP J-6B:XI Diesel Generator 2-2 Startup 1

Notifications

50441192 50441193 50702486

A-2

Drawing

Number Title Revision

106703 OVID Unit 2 Auxiliary Feedwater System 50

Section 1R05: Fire Protection

Notifications

50673544 50317795 50695031 50702504 50778755

50697654 50685679 50698510 50697655 50684755

50697653 50698135 50622152

Drawings

Number Title Revision /

Date

RA-5 Pre-Fire Plans 85 foot Auxiliary Building 10

111906-17 Fire Protection 85 foot Auxiliary Building 10

515221-2 Door Schedule- Unit 1 February 20, 2015

515224-2 Door Schedule- Unit 2 March, 26, 2014

TB-14/16 Unit 2, Fire Plan- Turbine Building Elev. 85 foot 6

111906 Unit 2, Fire Protection Turbine Building Elev. 85 foot 6

108008 Chemical & Volume Control System 106

108026 Nitrogen and Hydrogen Systems-Unit 1 25

Procedures

Number Title Revision

CF3.ID11 Seismic Configuration Control Program 9

AD7.DC8 Work Planning 45A

AD7.DC6 On-Line Maintenance Risk Management 21B

OM8 Fire Protection Program 4

OM8.ID1 Fire Loss Prevention 25

OM8.ID2 Fire System Impairment 18

OM8.ID4 Control of Flammable and Combustible Materials 22A

TP TO-15001 VCT H2 Regulator PCV-955 Repair or Replacement 0

A-3

Miscellaneous Document

Number Title Date

C19 D-08-027 Clearance H2 Supply Regulator to VCT 1-1 January 28, 2015

Section 1R06: Flood Protection Measures

Notifications

50509840 50508365

Drawings

Number Title Revision

515220-2 Unit 1 Door Schedule Operational Requirements 26

515220-1 Unit 1 Door Schedule 61

Section 1R11: Licensed Operator Requalification Program and Licensed Operator

Performance

Procedures

Number Title Revision

R137-EI-1 Instructors lesson Scenario Guide 20

TQ2.DC3 Licensed Operator and Shift Technical Advisors 25

Continuing Training Program

TQ2.DC15 Licensed Operator Annual/Biennial Exam 3

Development and Administration Guidelines

TQ2.ID4 Lesson Scenario Plan 0

TQ2.DC15 Licensed Operator Annual/Biennial Exam 5

Development and Administration

TQ2.DC3 Licensed Operator Continuing Training Program 26

TQ1.DC.28 Simulator Testing 1

SQA 99-2 Operator Training Simulator Software Quality 2

Assurance

CF2.DC1 Configuration Management Plan for the Operator 9

Training Simulator

CF4.ID3 Modification Implementation 29

STA-213 Use of RETRAN to Assess DCPP Plant Simulator 0

Operability Testing Performance

TQ2.ID4 Training Program Implementation 38

A-4

Procedures

Number Title Revision

OP1.ID2 Time Critical Operator Actions 8A

OP1.DC10 Conduct of Operations 43

OM14.ID2 Medical Examinations 9

TQ2.DC13 Shift Technical Advisor/Incident Assessor Training 2

Program

Miscellaneous Documents

Number Title Revision /

Date

NRC Pre-Inspection Self-Assessment Report March 10, 2015

Shift Manager / STA / IA Self-Assessment Report December 25, 2014

Simulator Review Team Quarterly Meeting Minutes January 9, 2014

Simulator Review Team Quarterly Meeting Minutes June 12, 2014

Simulator Review Team Meeting Minutes January 22, 2015

Simulator Review Team Quarterly Meeting Minutes September 26, 2013

Simulator Review Team Quarterly Meeting Minutes June 27, 2013

Simulator Review Team Quarterly Meeting Minutes March 27, 2013

Simulator Review Team Meeting Minutes March 31, 2015

LOCT CRC Ad Hoc Meeting Minutes April 9, 2015

LOCT Curriculum Review Committee Meeting January 9, 2014

Minutes

LOCT Curriculum Review Committee Meeting November 19, 2014

Minutes

LOCT Curriculum Review Committee Meeting January 28, 2015

Minutes

B.3.2.1(2) Transient Test Trip of All Feedwater Pumps September 6, 2014

B3.2.1(7) Transient Test Maximum Rate Power Ramp September 6, 2014

B3.2.1(10) Transient Test Stuck PORV without High Head September 13, 2014

ECCS

Simulator/Plant Differences of Note

SCR 2013-055 Model New Alarm Input 1625 on PK2020 January 24, 2015

SCR 2012-050 1R18 Mod for U1 MBT Oil Pump Replacement January 24, 2015

A-5

Miscellaneous Documents

Number Title Revision /

Date

DCP Design Change Package Summary 0

1000024867

SBT Loss of Condenser Vacuum February 23, 2015

SBT Loss of Reactor Pressure Control February 23, 2015

SBT NI-44 Failure February 23, 2015

2013-2014 LOCT POI 2

SCR 2012-013 Evaluate if Emergency Borate Flow is Correct

SCR 2014-058 RHR Discharge Pressure Increases to Relief

Setpoint on Safety Injection Where RCS Pressure

is Above Shutoff Head

SCR 2013-027 Correct Rod Lo/Lo-Lo Alarms on S/U

SCR 2012-025 Update CST Lo Level Alarm LS478 Setpoint

DDP Design Change Package Summary 0

1000000469

Simulator Determination of Moderator Temperature March 13, 2014

Coefficient at HZP, BOL

Simulator Rod Worth Measurements Using Rod March 13, 2014

Swap Method

Control Room Log Entries 2/8/14 & 10/5/14

Crew D training records

Licensed Operator Reactivation Records

Annual Operating Tests

Biennial Written Examination

R147 Remediation Package for RO 2015 Biennial Exam April 22, 2015

R137 Remediation Package for 2014 Annual Exam May 23, 2014

40% plant comp 2014.xls (40 percent steady state

simulator test data)

18% plant comp 2014.xls (18 percent steady state

simulator test data)

A-6

Notifications

50549004 50556077 50592099 50627628 50688192

50694912 50698753 50703049 50703106 50703139

50703258 50703259 50703308 50703369 50703411

50703413 50703414 50703422 50703423 50703448

50703449 50703485 50703496 50703550 50703551

50703556 50703557 50657245

Section 1R12: Maintenance Effectiveness

Notifications

50698248 50698528 50673779 50673158 5067566

50683171

Work Order 60078762

Section 1R13: Maintenance Risk Assessments and Emergent Work Control

Procedures

Number Title Revision /

Date

OP J-2:VII Offsite Power Sources - de-energizing 10

PGE DW-15-0192 Switching Log and Clearance Setup April 9, 2015

AD7.DC6 On-Line Maintenance Risk Management 21B

AD7.ID14 Assessment of Integrated Risk 1

OP J-2:VIII Guideline for Reliable Transmission Service for DCPP 26

AD7.ID14 Assessment of Integrated Risk 5

Notifications

50231071 50425987 50704663 50708371 50708054

50673779 50673158 5067566

A-7

Drawings

Number Title Revision /

Date

LCOTR 0-TS-15- Tracking Technical Specification Report April 22, 2015

0056

0-C19 D-18-047 Carbon Dioxide Hose Reel Clearance Scope April, 22, 2015

Calculation File PRA Evaluation of Various Maintenance Configurations to 4

No. C13 Support On-Line Risk Assessment

Section 1R15: Operability Determinations and Functionality Assessments

Procedure

Number Title Revision

OM10.DC3 Emergency Response Facilities, Equipment, and 7

Resources

Notifications

50695180 50695372 50687000 50687004 50698075

50703770 50673779 50673158 5067566 505697487

Section 1R18: Plant Modifications

Procedures

Number Title Revision

TP TO-13007 Traveling Screen 2-7 Replacement Contingencies 1

CF4 Modification Control 7

Notifications

60017014 50250296

Section 1R19: Post-Maintenance Testing

Procedures

Number Title Revision

STP-P-DFO-02 Routine Surveillance Test of Diesel Fuel Oil Transfer Pump 9

0-1

AD13.ID4 Post Maintenance Testing 22B

A-8

Procedures

Number Title Revision

STP-M-51 Routine Surveillance Test of Containment Fan Cooler Units 36

MP E-50.30B Agastat Type ETR Timing Relay Maintenance 25

Notifications

50700093 50606336 50701876 50701916 50699768

50704308 50703393 50704452

Work Orders

64068095 64113509 60079526

Section 1R22: Surveillance Testing

Procedures

Number Title Revision

STP P-ASW-A11 Comprehensive Test of Auxiliary Saltwater Pump 1-1 8

STP I-38-B.1 SSPS Train B Actuation Logic Test in Modes 1,2,3, or 4 25

STP I-38-B.2 SSPS Train B SI Reset Timer and Slave Relay K602 Test 10

STP M-9G Diesel Generator 24-Hour Load Test and Hot Restart Test 54

Notifications

50703698 50705639

Work Orders

64079112 64077108 64077118

Section 1EP6: Drill Evaluation

Procedures

Number Title Revision

EN-1 PEP Plant Accident Mitigation Diagnostic Aids and Guidelines 25

OP H-5:1 Control Room Ventilation - Prepare for Service R17

A-9

Notifications

50683410 50706695 50706696 50706697

Section 4OA2: Problem Identification and Resolution

Procedure

Number Title Revision

STP M-70.SWG Swing Door Surveillance Test 1

Notifications

50698455 50698102 50710846 50659268 50496405

Other Documents

Number Title Revision

M-493 Calculation Area H&K Auxiliary Building Pressure and 2

Temperatures due to Pipe Breaks

DCM T-12 Pipe Break (HELB/MELB), Flooding and Missiles Design 14C

Change DCP M-49919

Section 4OA3: Follow-up of Events and Notices of Enforcement Discretion

Procedures

Number Title Revision

SDP-13-07 High Wind Effect on Unit 1 EDG Ventilation System 0

SDP-13-06 Loss of Local Control of EDG 1-3 Output Breaker 0

Notifications

50599190 50595473 50484887 50702970 50703118

50596870 50669226 50700062 50682553 50603815

50683219 50688823 50231071 50707353 50669932

50573100 50702094 50699875 50627559 50586410

Procedures

Number Title Revision

OP AP-8A Control Room Inaccessibility - Hot Standby 38

A-10

Procedures

Number Title Revision

OP AP-8B Control Room Inaccessibility - Coly Shutdown 26TP

DCPP Scoping System 69: 230 kV System 2

OM1.ID4 Interface Requirements for Transmission & Distribution 6A

Facilities at DCPP

AWP E-016 Inspection Guide - Maintenance Rule & License Renewal 6

Structural Monitoring Programs - Civil

MA1.NE1 Maintenance Rule Monitoring Program -Civil 5

Implementation

MA1.ID17 Maintenance Rule Monitoring Program 28

OP J-2:VII Offsite Power Sources - Deenergizing SUT 1-1 & 2-1 for 10

230 kV Maintenance

OM7.ID1 Problem Identification and Resolution 46

A-11